WPS RESOURCES
CORPORATION AND SUBSIDIARIES
WISCONSIN
PUBLIC SERVICE CORPORATION AND SUBSIDIARY
CONDENSED
NOTES TO FINANCIAL STATEMENTS
September 30,
2005
NOTE
1--FINANCIAL INFORMATION
We
have prepared the condensed consolidated financial statements of
WPS Resources and WPSC under the rules and regulations of the SEC. These
financial statements have not been audited. Management believes that these
financial statements include all adjustments (which unless otherwise noted
include only normal recurring adjustments) necessary for a fair presentation
of
the financial results for each period shown. Certain items from the prior
period
have been reclassified to conform to the current year presentation. We have
condensed or omitted certain financial information and footnote disclosures
normally included in our annual audited financial statements. These financial
statements should be read along with the audited financial statements and
notes
included in our Annual Report on Form 10-K for the year ended December 31,
2004, and along with the revised financial statements and related disclosures
included in the Current Report on Form 8-K dated August 25, 2005 (filed with
the
SEC on August 26, 2005).
For
all periods
presented, certain assets and liabilities of Sunbury have been reclassified
as
held and used and Sunbury's results of operations and cash flows have been
reclassified into continuing operations. See Note 4, Assets
Held for
Sale,
for more
information.
NOTE
2--CASH AND CASH EQUIVALENTS
We
consider short-term investments with an original maturity of three months
or less to be cash equivalents.
The
following is
supplemental disclosure to the WPS Resources and WPSC Condensed
Consolidated Statements of Cash Flows:
|
|
|
|
(Millions)
|
|
Nine
Months
Ended September 30
|
|
WPS Resources
|
|
2005
|
|
2004
|
|
Cash
paid for
interest
|
|
$
|
38.9
|
|
$
|
34.1
|
|
Cash
paid for
income taxes
|
|
|
47.4
|
|
|
26.7
|
|
|
|
|
|
|
|
|
|
WPSC
|
|
|
|
|
|
|
|
Cash
paid for
interest
|
|
$
|
21.1
|
|
$
|
19.9
|
|
Cash
paid for
income taxes
|
|
|
39.5
|
|
|
25.3
|
|
During
the nine
months ended September 30, 2005, accounts payable related to Weston 4
construction costs increased approximately $23.6 million, and accordingly,
are treated as non-cash investing activities. Weston 4 construction costs
funded
through accounts payable were not significant during the nine months ended
September 30, 2004.
NOTE
3--RISK MANAGEMENT ACTIVITIES
As
part of our regular operations, WPS Resources enters into contracts,
including options, swaps, futures, forwards, and other contractual commitments,
to manage market risks such as changes in commodity prices and interest
rates.
WPS Resources
accounts for its derivative contracts in accordance with SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended
and
interpreted. SFAS No. 133 establishes accounting and financial reporting
standards for derivative instruments and requires, in part, that we recognize
certain derivative instruments on the balance sheet as assets or liabilities
at
their fair value. Subsequent changes in fair value of the derivatives are
recorded currently in earnings unless certain
hedge
accounting
criteria are met. If the derivatives qualify for regulatory deferral subject
to
the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types
of Regulation," the derivatives are marked to fair value pursuant to SFAS
No. 133 and are offset with a corresponding regulatory asset or
liability.
The
following table
shows WPS Resources’ assets and liabilities from risk management
activities:
|
|
|
|
|
|
|
|
Assets
|
|
Liabilities
|
|
(Millions)
|
|
September 30,
2005
|
|
December 31,
2004
|
|
September 30,
2005
|
|
December 31,
2004
|
|
Utility
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and electric purchase contracts
|
|
$
|
31.6
|
|
$
|
11.0
|
|
$
|
-
|
|
$
|
-
|
|
Financial transmission rights
|
|
|
25.6
|
|
|
-
|
|
|
3.5
|
|
|
0.6
|
|
Nonregulated
Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and foreign currency
contracts
|
|
|
1,450.7
|
|
|
396.5
|
|
|
1,387.1
|
|
|
366.6
|
|
Fair
value hedges
|
|
|
4.9
|
|
|
3.8
|
|
|
32.8
|
|
|
2.3
|
|
Cash
flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
84.1
|
|
|
39.8
|
|
|
132.9
|
|
|
22.9
|
|
Interest rate swaps
|
|
|
-
|
|
|
-
|
|
|
5.5
|
|
|
8.7
|
|
Total
|
|
$
|
1,596.9
|
|
$
|
451.1
|
|
$
|
1,561.8
|
|
$
|
401.1
|
|
Balance
Sheet Presentation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
1,355.9
|
|
$
|
376.5
|
|
$
|
1,364.0
|
|
$
|
338.6
|
|
Long-Term
|
|
|
241.0
|
|
|
74.6
|
|
|
197.8
|
|
|
62.5
|
|
Total
|
|
$
|
1,596.9
|
|
$
|
451.1
|
|
$
|
1,561.8
|
|
$
|
401.1
|
|
Assets
and
liabilities from risk management activities are classified as current or
long-term based upon the maturities of the underlying financial
instruments.
Utility
Segment
WPSC
has entered
into a limited number of natural gas and electric purchase contracts that
are
accounted for as derivatives and shown in the above table. In addition,
"Financial transmission rights" includes financial instruments used to manage
the transmission congestion costs of the electric utility. The PSCW approved
the
recognition of a regulatory asset or liability for the fair value of derivative
amounts. Thus, management believes any gains or losses resulting from the
eventual expiration or settlement of these derivative instruments will be
collected from or refunded to customers.
Nonregulated
Segments
The
derivatives in
the nonregulated segments not designated as hedges under generally accepted
accounting principles are primarily commodity contracts used to manage price
risk associated with natural gas purchase and sale activities, electric energy
contracts, and foreign currency contracts used to manage foreign currency
exposure related to our nonregulated Canadian businesses. In addition, PDI
entered into a series of derivative contracts (options) covering a specified
number of barrels of oil in order to manage exposure to the risk of an increase
in oil prices that could reduce the amount of Section 29 federal tax credits
that can be recognized from PDI's investment in a synthetic fuel production
facility for 2005-2007. See Note 11, Commitments
and
Contingencies,
for more
information. Changes in the fair value of non-hedge derivatives are recognized
currently in earnings.
Our
nonregulated
segments also enter into derivative contracts that are designated as either
fair
value or cash flow hedges. Fair value hedges are used to mitigate the risk
of
changes in the price of natural gas held in storage. The changes in the fair
value of these hedges are recognized currently in earnings, as are the changes
in fair value of the hedged items. Fair value hedge ineffectiveness recorded
in
nonregulated revenue on the Condensed Consolidated Statements of Income was
not
significant for the
nine
months ended
September 30, 2005, and 2004. At September 30, 2005, a pre-tax
mark-to-market loss of $5.1 million related to changes in the difference
between the spot and forward prices of natural gas was excluded from the
assessment of hedge effectiveness. This loss was reported directly in earnings.
The amount excluded from the assessment of hedge effectiveness at
December 31, 2004, was not significant.
Commodity
contracts
that are designated as cash flow hedges extend through October 2007 and are
used to mitigate the risk of cash flow variability associated with the future
purchases and sales of natural gas and electricity. To the extent they are
effective, the changes in the values of these contracts are included in other
comprehensive income, net of deferred taxes. Cash flow hedge ineffectiveness
recorded in nonregulated revenue on the Condensed Consolidated Statements
of
Income related to commodity contracts was not significant for the nine months
ended September 30, 2005, and 2004. When testing for effectiveness, no
portion of the derivative instruments was excluded. Amounts recorded in other
comprehensive income related to these cash flow hedges will be recognized
in
earnings as the related contracts are settled, if the hedge becomes ineffective,
or if it is probable that the hedged transaction will not occur. During the
nine
months ended September 30, 2005, and September 30, 2004, we
reclassified a $3.1 million and a $2.8 million net-of-tax gain,
respectively, from other comprehensive income into earnings as a result of
the
discontinuance of cash flow hedge accounting for certain hedge transactions.
In
the next 12 months, subject to changes in market prices of natural gas and
electricity, we expect that a net-of-tax loss of $27.4 million will be
recognized in earnings as contracts are settled. We expect this amount to
be
substantially offset by settlement of the related nonderivative contracts.
In
the second quarter of 2005, a variable rate non-recourse debt instrument
used to
finance the purchase of Sunbury was restructured to a WPS Resources obligation.
An interest rate swap used to fix the interest rate on the Sunbury non-recourse
debt had been previously designated as a cash flow hedge. As a result of
the
debt restructuring, the hedged transaction will no longer occur. This resulted
in the recognition of a $9.1 million pre-tax loss (equivalent to the
mark-to-market value of the swap at the date of restructuring), which was
recorded as a component of interest expense in the second quarter of 2005.
This
loss was previously deferred as a component of other comprehensive income
pursuant to hedge accounting rules. Subsequent to the restructuring, the
interest rate swap was re-designated as a cash flow hedge, along with an
additional interest rate swap, to fix the interest rate on the WPS Resources
obligation. The changes in the fair value of the effective portion of these
swaps are included in other comprehensive income, net of deferred taxes,
while
the changes related to the ineffective portion are recorded in earnings.
During
the nine months ended September 30, 2005, cash flow hedge ineffectiveness
recorded in earnings related to these swaps was not significant. Amounts
recorded in other comprehensive income related to these swaps will be recognized
as a component of interest expense as the interest becomes due. In the next
12
months, we expect to recognize $0.1 million in interest expense related to
these swaps, assuming interest rates comparable to those at September 30,
2005. We did not exclude any components of the derivative instruments' change
in
fair value from the assessment of hedge effectiveness.
NOTE
4--ASSETS HELD FOR SALE
In
the second quarter of 2005, PDI sold all of Sunbury's allocated emission
allowances. Prior to this decision, PDI had marketed for sale the Sunbury
plant
and certain other related assets (primarily inventory and unallocated emission
allowances) in combination with the allocated emission allowances. The Sunbury
facility sells power on a wholesale basis and previously provided energy
for a
200-megawatt around-the-clock outtake contract that expired on
December 31, 2004. Following Duquesne Power, L.P.'s termination of the
previously announced agreement to sell Sunbury to Duquesne for
approximately $120 million, PDI continued to pursue the sale of Sunbury
with the assistance of an investment banking firm, but a suitable buyer was
not
found.
Total
sales
proceeds from the sale of Sunbury's emission allowances were
$109.9 million, resulting in a pre-tax gain of $85.9 million. The sale
of the emission allowances provides PDI with more time to consider various
alternatives for the Sunbury plant. All available solid fuel units at the
Sunbury plant were operated through September 30, 2005 due to favorable market
conditions. Should market conditions decline, PDI will consider placing the
plant in a stand-by mode of operation, which serves to minimize
future
operating
expenses while maintaining several options (including closing the plant,
retaining the plant and operating it during favorable economic periods, or
a
potential future sale of the plant).
Prior
to the
decision to sell the allocated emission allowances separately, the Sunbury
plant, allocated emission allowances, and other related assets had been
classified as held for sale as a combined asset disposal group, and Sunbury's
results of operations and related cash flows had been reported as discontinued
operations. However, because PDI is no longer committed to the sale of Sunbury
as its only option, generally accepted accounting principles require those
assets and liabilities previously classified as held for sale that no longer
meet the held for sale criteria outlined in SFAS No. 144, "Accounting for
the
Impairment or Disposal of Long-Lived Assets," to be reclassified to the
appropriate held and used categories for all periods presented. As a result,
the
allocated emission allowances that were sold in May 2005 remain classified
as held for sale for all applicable periods presented, but the Sunbury plant,
unallocated emission allowances, and other related assets and liabilities
were
reclassified as held and used. Furthermore, Sunbury's results of operations
were
reclassified as components of continuing operations for all periods
presented.
All
long-lived
assets reclassified as held and used are required to be recorded individually
at
the lower of their carrying value before they were classified as assets held
for
sale (adjusted for any depreciation expense that would have been recognized
had
they been continuously classified as held and used) or fair value at the
date
the held for sale criteria was no longer met. Upon reclassification of the
Sunbury plant and related assets as held and used in the second quarter of
2005,
PDI recorded a non-cash, pre-tax impairment charge of $80.6 million. The
impairment charge substantially offset the gain on the sale of the emission
allowances.
The
major classes
of assets held for sale are as follows:
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Property,
plant, and equipment, net
|
|
$
|
0.8
|
|
$
|
0.8
|
|
Other
assets:
|
|
|
|
|
|
|
|
Emission
allowances
|
|
|
-
|
|
|
23.3
|
|
Assets
held
for sale
|
|
$
|
0.8
|
|
$
|
24.1
|
|
PDI
financed
Sunbury with equity from WPS Resources and debt financing, including
non-recourse debt and a related interest rate swap. The interest rate swap
was
designated as a cash flow hedge. WPS Resources is required to recognize the
amount accumulated within other comprehensive income currently in earnings
if
management determines that the hedged transactions (i.e., future interest
payments on the debt) will not continue. Sunbury's non-recourse debt was
restructured to a WPS Resources obligation in the second quarter of 2005 in
conjunction with the sale of Sunbury's allocated emission allowances. The
restructuring of the Sunbury non-recourse debt to a WPS Resources obligation
triggered a $9.1 million pre-tax loss (the mark-to-market value of the swap
at the date of the restructuring), which was recorded as a component of interest
expense in the second quarter of 2005. This loss was previously deferred
as a
component of other comprehensive income pursuant to hedge accounting
rules.
NOTE
5--ACQUISITIONS AND SALES OF ASSETS
Agreement
to Purchase Aquila's Michigan and Minnesota Natural Gas Distribution
Operations
On
September 21, 2005, WPS Resources, through wholly owned subsidiaries,
entered into two definitive agreements with Aquila, Inc. to acquire Aquila's
natural gas distribution operations in Michigan and Minnesota for approximately
$558 million, exclusive of direct costs of the acquisition. The purchase
price also excludes certain adjustments related to working capital, including
accounts receivable, unbilled revenue, inventory, and certain other current
assets. The purchase price is also subject to certain other closing and
post-closing adjustments, primarily net plant adjustments.
The
Minnesota
natural gas assets provide natural gas distribution service to about 200,000
customers throughout the state in 165 cities and communities including Grand
Rapids, Pine City, Rochester, and Dakota County with 226 employees. Annual
natural gas throughput is approximately 761 million therms per year, which
is almost as large as WPS Resources' existing regulated natural gas operations.
The assets operate under a cost-of-service environment and are currently
allowed
an 11.71% return on equity on a 50% equity component of the regulatory capital
structure.
The
Michigan
natural gas assets provide natural gas distribution service to about 161,000
customers, mainly in southern Michigan in 147 cities and communities including
Otsego, Grand Haven, and Monroe with 182 employees. Annual natural gas
throughput is approximately 360 million therms per year. Like Minnesota,
the assets also operate under a cost-of-service environment and are currently
allowed an 11.4% return on equity on a 45% equity component of the regulatory
capital structure.
WPS
Resources plans
that permanent financing for the acquisition will be raised through the issuance
of a combination of equity and long-term debt.
The
transaction is
subject to various state and other regulatory approvals, including approval
from
the Michigan Public Service Commission and the Minnesota Public Utilities
Commission, and is subject to compliance with the Hart-Scott-Rodino Act.
Assuming all approvals are obtained in a timely manner, WPS Resources
anticipates closing both transactions in the first half of 2006.
Kewaunee
Nuclear Power Plant
In
early July 2005, Kewaunee returned to service following an unplanned outage
that
began in February 2005. On July 5, 2005, WPSC completed the sale of its 59%
ownership interest in Kewaunee to Dominion Energy Kewaunee, LLC, a subsidiary
of
Dominion Resources, Inc. At the same time, Wisconsin Power and Light Company
sold its 41% ownership interest to Dominion. The major benefits of the sale
for
WPSC included shifting financial risk from utility customers and shareholders
to
Dominion, greater certainty of future costs, and the return of the nonqualified
decommissioning funds to customers.
WPSC's
share of the
cash proceeds from the sale was $112.5 million. Dominion received the
assets in WPSC's qualified decommissioning trust and assumed responsibility
for
the eventual decommissioning of Kewaunee. These trust assets had a pre-tax
fair
value of $243.6 million at closing. WPSC retained ownership of the assets
contained in its nonqualified decommissioning trust. The sale of Kewaunee
resulted in a loss of $12.1 million, which includes the proceeds from the
sale less the net assets sold, adjusted by several additional items. The
most
significant of these adjustments is the fair value of an indemnity issued
to
cover certain costs Dominion may incur related to the recent unplanned outage.
In addition, the adjustments include certain costs related to the termination
of
the plant operating agreement and withdrawal from WPS Resources' investment
in
the Nuclear Management Company ("NMC"), which served as the licensed operator
of
Kewaunee. WPSC has received approval from the PSCW for deferral of the loss
resulting from this transaction and related costs. WPSC has proposed that
proceeds of $127.1 million received from the liquidation of the
nonqualified decommissioning trust assets be refunded to customers, net of
the
loss on the sale of the plant assets and costs related to the 2004 and 2005
Kewaunee outages. See Note 16, Regulatory
Environment,
for more
information.
At
the closing date, WPSC's share of the carrying value of the assets and
liabilities that were included within the sale agreement, or that were otherwise
eliminated pursuant to the sale, were as follows:
|
|
|
|
(Millions)
|
|
July
5, 2005
|
|
|
|
|
|
Qualified
decommissioning trust fund
|
|
$
|
243.6
|
|
Other
utility
plant, net
|
|
|
165.4
|
|
Other
current
assets
|
|
|
5.5
|
|
Total
assets
|
|
$
|
414.5
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
$
|
(72.1
|
)
|
Accounts
payable
|
|
|
2.5
|
|
Asset
retirement obligations
|
|
|
376.4
|
|
Total
liabilities
|
|
$
|
306.8
|
|
Upon
the closing of
the sale, WPSC entered into a long-term power purchase agreement with Dominion
to purchase energy and capacity consistent with volumes available when WPSC
owned Kewaunee. The power purchase agreement extends through 2013 when the
plant's current operating license will expire. Fixed monthly payments under
the
power purchase agreement will approximate the expected costs of production
had
WPSC continued to own the plant. Therefore, management believes that the
sale of
Kewaunee and the related power purchase agreement provides more price certainty
for WPSC's customers and reduces WPSC's risk profile. In April 2004, WPSC
entered into an exclusivity agreement with Dominion. Under this agreement,
if
Dominion decides to extend the operating license of Kewaunee, Dominion can
negotiate only with WPSC during the exclusivity period for 59% of the plant
output under a new power purchase agreement that would extend beyond Kewaunee's
current operating license termination date. The exclusivity period started
on
the closing date of the sale, July 5, 2005, and extends through
December 21, 2011, after which Dominion can negotiate with other
parties.
NOTE
6--GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
recorded
by WPS Resources was $36.8 million at September 30, 2005, and
December 31, 2004. Of this amount, $36.4 million is recorded in WPSC's
natural gas segment relating to its merger with Wisconsin Fuel and Light.
The
remaining $0.4 million of goodwill relates to PDI.
Goodwill
and
purchased intangible assets are included in other assets on the Condensed
Consolidated Balance Sheets. Emission allowances are recorded at the lower
of
cost or market. Information in the tables below relates to total purchased
identifiable intangible assets for the periods indicated.
|
|
|
|
(Millions)
|
|
September 30,
2005
|
|
Asset
Class
|
|
Average
Life
(Years)
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Emission
allowances
|
|
|
1
to 30
|
|
$
|
16.7
|
|
$
|
(13.0
|
)
|
$
|
3.7
|
|
Customer
related
|
|
|
1
to 8
|
|
|
10.5
|
|
|
(5.2
|
)
|
|
5.3
|
|
Other
|
|
|
1
to 30
|
|
|
4.2
|
|
|
(1.6
|
)
|
|
2.6
|
|
Total
|
|
|
|
|
$
|
31.4
|
|
$
|
(19.8
|
)
|
$
|
11.6
|
|
|
|
|
|
|
|
(Millions)
|
|
December 31,
2004
|
Asset
Class
|
|
|
Average
Life
(Years)
|
|
|
Gross
Carrying
Amount
|
|
|
Accumulated
Amortization
|
|
|
Net
|
|
Emission
allowances
|
|
|
1
to 30
|
|
$
|
15.8
|
|
$
|
(0.9
|
)
|
$
|
14.9
|
|
Customer
related
|
|
|
1
to 8
|
|
|
11.2
|
|
|
(4.6
|
)
|
|
6.6
|
|
Other
|
|
|
1
to 30
|
|
|
4.2
|
|
|
(1.6
|
)
|
|
2.6
|
|
Total
|
|
|
|
|
$
|
31.2
|
|
$
|
(7.1
|
)
|
$
|
24.1
|
|
An
impairment charge related to Sunbury, which was recorded in the second quarter
of 2005, included the write-down of $6.6 million of unallocated emission
allowances. These emission allowances were reflected in the above table at
December 31, 2004 (see Note 4, Assets
Held for
Sale,
for more
information).
Because PDI sold all of Sunbury's allocated emission allowances in the first
half of 2005, emission allowances are currently purchased in the market as
needed for the operation of this plant.
Intangible
asset
amortization expense, in the aggregate, for the nine months ended
September 30, 2005, and September 30, 2004, was
$13.1 million and $1.7 million, respectively. Intangible asset
amortization expense, in the aggregate, for the three months ended
September 30, 2005, and September 30, 2004, was $10.1 million and
$1.0 million, respectively. Amortization expense for the next five fiscal
years is estimated as follows:
Estimated
Future Amortization Expense:
|
|
For
three
months ending December 31, 2005
|
$1.9 million
|
For
year
ending December 31, 2006
|
1.6 million
|
For
year
ending December 31, 2007
|
1.3 million
|
For
year
ending December 31, 2008
|
1.5 million
|
For
year
ending December 31, 2009
|
1.2 million
|
NOTE
7--SHORT-TERM DEBT AND LINES OF CREDIT
WPS Resources
has a syndicated $500 million five-year revolving credit facility which
expires in June 2010. WPSC has a syndicated $115 million five-year
revolving credit facility containing annual trigger date provisions to provide
short-term borrowing flexibility and security for commercial paper
outstanding.
The
information in
the table below relates to WPS Resources' short-term debt and lines of credit
as
of the time periods indicated.
|
|
|
|
|
|
(Millions)
|
|
September 30,
2005
|
|
December 31,
2004
|
|
Commercial
paper outstanding
|
|
$
|
138.0
|
|
$
|
279.7
|
|
Average
discount rate on outstanding commercial paper
|
|
|
3.95
|
%
|
|
2.46
|
%
|
Short-term
notes payable outstanding
|
|
$
|
10.0
|
|
$
|
12.7
|
|
Average
interest rate on short-term notes payable
|
|
|
3.67
|
%
|
|
2.52
|
%
|
Available
under lines of credit
|
|
$
|
404.5
|
|
$
|
161.9
|
|
The
commercial
paper at September 30 had varying maturity dates ranging from October 3
through October 17, 2005.
The
information in
the table below relates to WPSC's short-term debt and lines of credit as
of the
time periods indicated.
|
|
|
|
|
|
(Millions)
|
|
September 30,
2005
|
|
December 31,
2004
|
|
Commercial
paper outstanding
|
|
$
|
32.0
|
|
$
|
91.0
|
|
Average
discount rate on outstanding commercial paper
|
|
|
3.94
|
%
|
|
2.44
|
%
|
Short-term
notes payable outstanding
|
|
$
|
10.0
|
|
$
|
10.0
|
|
Average
interest rate on short-term notes payable
|
|
|
3.67
|
%
|
|
2.26
|
%
|
Available
under lines of credit
|
|
$
|
79.2
|
|
$
|
20.2
|
|
The
commercial
paper had varying maturity dates ranging from October 7 through October 17,
2005.
NOTE
8--LONG-TERM DEBT
(Millions)
|
September 30, 2005
|
December 31, 2004
|
|
|
|
First
mortgage bonds – WPSC
|
|
|
|
Series
|
Year
Due
|
|
|
|
6.90%
|
2013
|
$
22.0
|
$
22.0
|
|
7.125%
|
2023
|
0.1
|
0.1
|
|
|
|
Senior
notes
– WPSC
|
|
|
|
Series
|
Year
Due
|
|
|
|
6.125%
|
2011
|
150.0
|
150.0
|
|
4.875%
|
2012
|
150.0
|
150.0
|
|
4.80%
|
2013
|
125.0
|
125.0
|
|
6.08%
|
2028
|
50.0
|
50.0
|
|
|
|
First
mortgage bonds – UPPCO
|
|
|
|
Series
|
Year
Due
|
|
|
|
9.32%
|
2021
|
15.3
|
15.3
|
|
|
|
Unsecured
senior notes – WPS Resources
|
|
|
|
Series
|
Year
Due
|
|
|
|
7.00%
|
2009
|
150.0
|
150.0
|
|
5.375%
|
2012
|
100.0
|
100.0
|
|
|
|
Unsecured
term loan due 2010 – WPS Resources
|
65.6
|
-
|
Term
loans –
non-recourse, collateralized by nonregulated assets
|
17.7
|
82.3
|
Tax
exempt
bonds
|
27.0
|
27.0
|
Senior
secured note
|
2.5
|
2.7
|
Total
|
875.2
|
874.4
|
Unamortized
discount and premium on bonds and debt
|
(1.9)
|
(2.0)
|
Total
long-term debt
|
873.3
|
872.4
|
Less
current
portion
|
(3.7)
|
(6.7)
|
Total
long-term debt
|
$869.6
|
$865.7
|
On
June 17, 2005,
$62.9 million of non-recourse debt at PDI collateralized by nonregulated
assets was converted to a five-year WPS Resources obligation as a result
of the
sale of Sunbury's allocated emission allowances. In addition, $2.7 million
drawn on a line of credit at PDI was rolled into the five-year
WPS Resources obligation. The floating interest rate on the total five-year
WPS Resources’ obligation of $65.6 million has been fixed at 4.595% through
two interest rate swaps.
NOTE
9--ASSET RETIREMENT OBLIGATIONS
Legal
retirement
obligations, as defined by the provisions of SFAS No. 143, "Accounting for
Asset
Retirement Obligations," previously identified at WPSC related primarily
to the
final decommissioning of Kewaunee. As discussed in Note 5, Acquisitions
and Sales of Assets,
the sale of
Kewaunee to Dominion was completed on July 5, 2005. As a result of the sale,
Dominion assumed the asset retirement obligation related to
Kewaunee.
PDI
identified a
legal retirement obligation related to the closure of an ash basin located
at
Sunbury. The asset retirement obligation associated with Sunbury is recorded
as
a liability on the Condensed Consolidated Balance Sheets.
The
following table
describes all changes to the asset retirement obligation liabilities of
WPS Resources.
|
|
|
|
|
|
|
|
(Millions)
|
|
WPSC
|
|
PDI
|
|
Total
|
|
Asset
retirement obligation at December 31, 2004
|
|
$
|
364.4
|
|
$
|
2.2
|
|
$
|
366.6
|
|
Accretion
expense
|
|
|
12.4
|
|
|
0.2
|
|
|
12.6
|
|
Asset
retirement obligation transferred to Dominion
|
|
|
(376.4
|
)
|
|
-
|
|
|
(376.4
|
)
|
Asset
retirement obligation at September 30, 2005
|
|
$
|
0.4
|
|
$
|
2.4
|
|
$
|
2.8
|
|
NOTE
10--INCOME TAXES
For
the three and
nine months ended September 30, 2005, and 2004, WPS Resources' and WPSC's
provision for income taxes was calculated in accordance with APB Opinion
No. 28, "Interim Financial Reporting." Accordingly, our interim effective
tax
rate reflects our projected annual effective tax rate. The effective tax
rate
differs from the federal tax rate of 35%, primarily due to the effects of
tax
credits and state income taxes.
NOTE
11--COMMITMENTS AND CONTINGENCIES
Commodity
and Purchase Order Commitments
WPS Resources
routinely enters into long-term purchase and sale commitments that have various
quantity requirements and durations. The commitments described below are
as of
September 30, 2005.
ESI
has
unconditional purchase obligations related to energy supply contracts that
total
$4.2 billion.
Substantially all of these obligations end by 2009, with obligations totaling
$16.5 million extending from 2010 through 2015. The majority of the energy
supply contracts are to meet ESI's obligations to deliver energy to its
customers.
WPSC
has
obligations related to coal, purchased power, and natural gas. All pertinent
nuclear fuel contracts were assigned to Dominion with the July 5, 2005, sale
of
Kewaunee to Dominion. Obligations related to coal supply and transportation
extend through 2016 and total $346.5 million. Through 2016, WPSC has
obligations totaling $1.5 billion for either capacity or energy related to
purchased power, including the obligation under the power purchase agreement
with Dominion Kewaunee, LLC. Also, there are natural gas supply and
transportation contracts with total estimated demand payments of
$126.6 million through 2017. WPSC expects to recover these costs in future
customer rates. Additionally, WPSC has contracts to sell electricity and
natural
gas to customers.
PDI
has entered
into purchase contracts totaling $6.8 million. The majority of these
contracts relate to coal purchases for the PDI coal plants.
UPPCO
has made
commitments for the purchase of commodities, mainly capacity or energy related
to purchased power, which total $26.4 million and extend through
2010.
WPS Resources
also has commitments in the form of purchase orders issued to various vendors.
At September 30, 2005, these purchase orders totaled $485.7 million
and $471.6 million for WPS Resources and WPSC, respectively. The
majority of these commitments relate to large construction projects, including
construction of the 500-megawatt Weston 4 coal-fired generation facility
near
Wausau, Wisconsin.
EPA
Section
114 Request
In
November 1999, the EPA announced the commencement of a Clean Air Act enforcement
initiative targeting the utility industry. This initiative resulted in the
issuance of several notices of violation/findings of violation and the filing
of
lawsuits against utilities. In these enforcement proceedings, the EPA claims
that the utilities made modifications to the coal-fired boilers and related
equipment at the utilities' electric generation stations without first obtaining
appropriate permits under the EPA's pre-construction permit program and without
installing appropriate air pollution control equipment. In addition, the
EPA is
claiming,
in
certain situations, that there were violations of the Clean Air Act's "new
source performance standards." In the matters where actions have been commenced,
the federal government is seeking penalties and the installation of pollution
control equipment.
In
December 2000, WPSC received from the EPA a request for information under
Section 114 of the Clean Air Act. The EPA sought information and documents
relating to work performed on the coal-fired boilers located at WPSC's Pulliam
and Weston electric generation stations. WPSC filed a response with the EPA
in
early 2001.
On
May 22, 2002, WPSC received a follow-up request from the EPA seeking additional
information regarding specific boiler-related work performed on Pulliam Units
3,
5, and 7, as well as information on WPSC's life extension program for Pulliam
Units 3-8 and Weston Units 1 and 2. WPSC made an initial response to the
EPA's
follow-up information request on June 12, 2002, and filed a final response
on June 27, 2002.
In
2000 and 2002, Wisconsin Power and Light Company received a similar series
of
EPA information requests relating to work performed on certain coal-fired
boilers and related equipment at the Columbia generation station (a facility
located in Portage, Wisconsin, jointly owned by Wisconsin Power and Light
Company, Madison Gas and Electric Company, and WPSC). Wisconsin Power and
Light
Company is the operator of the plant and is responsible for responding to
governmental inquiries relating to the operation of the facility. Wisconsin
Power and Light Company filed its most recent response for the Columbia facility
on July 12, 2002.
Depending
upon the
results of the EPA's review of the information, the EPA may issue "notices
of
violation" or "findings of violation" asserting that a violation of the Clean
Air Act occurred and/or seek additional information from WPSC and/or third
parties who have information relating to the boilers or close out the
investigation. To date, the EPA has not responded to the filings made by
WPSC
and Wisconsin Power and Light. In addition, under the federal Clean Air Act,
citizen groups may pursue a claim.
In
response to the EPA Clean Air Act enforcement initiative, several utilities
have
elected to settle with the EPA, while others are in litigation. In general,
those utilities that have settled have entered into consent decrees which
require the companies to pay fines and penalties, undertake supplemental
environmental projects, and either upgrade or replace pollution controls
at
existing generating units or shut down existing units and replace these units
with new electric generating facilities. Several of the settlements involve
multiple facilities. The fines and penalties (including the capital costs
of
supplemental environmental projects) associated with these settlements range
between $7 million and $44 million. Factors typically considered in
settlements include, but are not necessarily limited to, the size and number
of
facilities as well as the duration of alleged violations and the presence
or
absence of aggravating circumstances. The regulatory interpretations upon
which
the lawsuits or settlements are based may change based on future court decisions
that may be rendered in pending litigations.
If
the federal government decided to bring a claim against WPSC and if it were
determined by a court that historic projects at WPSC's Pulliam and Weston
plants
required either a state or federal Clean Air Act permit, WPSC may, under
the
applicable statutes, be required to:
· |
shut
down any
unit found to be operating in
non-compliance,
|
· |
install
additional pollution control
equipment,
|
· |
pay
a fine
and conduct a supplemental environmental project in order to resolve
any
such claim.
|
At
the end of December 2002 and October 2003, the EPA issued new rules
governing the federal new source review program. These rules were subsequently
challenged in the District of Columbia Circuit Court of Appeals. On June
24,
2005, the District of Columbia Circuit Court of Appeals issued its opinion
on
the EPA's 2002 new source review reform rule. The ruling upheld most of the
2002
rule, but did strike down some provisions. The rules are not yet effective
in
Wisconsin. They are also not retroactive.
Wisconsin
has
proposed amending its new source review program to substantially conform
to the
federal regulations. The Wisconsin rules are not anticipated to be finalized
before 2006.
Pulliam
Air
Permit Violation Lawsuit
On
July 12, 2005, the Sierra Club and Clean Wisconsin notified WPS Resources
of
their intent to file a citizen enforcement action with the United States
District Court, Eastern District of Wisconsin, pursuant to the citizen suit
provisions of the Clean Air Act. The Sierra Club and Clean Wisconsin indicated
that the lawsuit will seek penalties, injunctive relief, and costs of
litigation. The notice referenced opacity exceedances reported by the Pulliam
facility located in Green Bay, Wisconsin, from 1999 through the first quarter
of
2005, and monitoring violations from 1999 through 2004. The notice also alleged
exceedances of the Clean Air Act operating permit in 2002, exceedances of
the
permit issued for eight diesel generators in 2001, and exceedances of the
permit
for the combustine turbine.
On
October 20, 2005, the Sierra Club and Clean Wisconsin filed a civil lawsuit
claiming that WPSC's Pulliam facility located in Green Bay, Wisconsin violated
provisions of its air permit with respect to particulates, nitrogen oxide,
and
visible emissions; however, WPSC has not been served to date. Sierra Club
and
Clean Wisconsin have stated a willingness to discuss the alleged violations.
WPSC is investigating the claims.
Weston
4
Air Permit
On
November 15, 2004, the Sierra Club filed a petition with the WDNR under Section
285.61, Wis. Stats., seeking a contested case hearing on the air permit issued
for the Weston 4 generation station. On December 2, 2004, WDNR granted the
petition and forwarded the matter to the Division of Hearings and Appeals.
In
its petition, Sierra Club raised legal and factual issues with the permit
and
with the process used by WDNR to develop the air emission limits and conditions.
In addition, both WPSC and the Sierra Club filed motions for summary judgment
on
certain of the issues. A decision regarding summary judgment was issued.
In the
ruling, the Administrative Law Judge denied the motion of Sierra Club and
granted summary judgment to WPSC with respect to certain claims of Sierra
Club
consistent with the rulings rendered in Wisconsin Energy's Elm Road proceeding.
The contested case hearing in the matter was held during the last week of
September 2005. The hearing addressed the remaining issues, which are generally
related to the emission limits specified in the permit and the pollution
controls to be used to achieve these limits. The Administrative Law Judge
set a
briefing schedule and indicated that a decision would be issued in January
2006.
If the Administrative Law Judge's decision requires modifications to the
air
permit, construction delays and/or increased construction costs could
result.
Weston
Site
Operation Permit
On
April 18 and April 26, 2005, WPS Resources notified the WDNR that the existing
Weston facility was not in compliance with certain provisions of the "Title
V"
air operating permit that was issued to the facility in October 2004. These
provisions include: (1) the particulate emission limits applicable to the
coal
handling equipment; (2) the carbon monoxide limit for Weston combustion
turbines; and (3) the limitation on the sulfur content of the fuel oil stored
at
the Weston facility. On July 27, 2005, WPSC received a notice of violation
(NOV)
from the WDNR asserting that the existing Weston facility is not in compliance
with certain provisions of the permit. The alleged noncompliance is based
on
information previously provided by WPSC to the WDNR in April 2005. The NOV
classifies certain alleged violations as "high priority" under the EPA's
high
priority violation policy. Under the WDNR’s stepped enforcement process, an NOV
is the first step in the WDNR’s enforcement procedure. If the WDNR decides to
continue the enforcement process, the next step is a “referral” of the matter to
the Wisconsin Attorney General’s Office. WPS Resources is seeking to amend
the applicable permit limits and is taking corrective action. At this time,
we
believe that our exposure to fines or penalties related to this noncompliance
would not have a material impact on our financial results.
Mercury
and
Interstate Air Quality Rules
On
October 1, 2004, the mercury emission control rule became effective in
Wisconsin. The rule requires WPSC to control annual system mercury emissions
in
phases. The first phase will occur in 2008 and 2009. In this phase, the annual
mercury emissions are capped at the average annual system mercury emissions
for
the period 2002 through 2004. The next phase will run from 2010 through 2014
and
requires a 40% reduction from average annual 2002 through 2004 mercury input
amounts. After 2015, a 75% reduction is required with a goal of an 80% reduction
by 2018. Because federal regulations were promulgated in March 2005, we believe
the state of Wisconsin will revise the Wisconsin rule to be consistent with
the
federal rule. However, the state of Wisconsin has filed suit against the
federal
government along with other states in opposition to the rule. WPSC estimates
capital costs of approximately $14 million to achieve the proposed 75%
reductions. The capital costs are expected to be recovered in a future rate
case.
In
December 2003, the EPA proposed mercury "maximum achievable control
technology" standards and an alternative mercury "cap and trade" program
substantially modeled on the Clear Skies legislation initiative. The EPA
also
proposed the Clean Air Interstate Rule (formerly known as the Interstate
Air
Quality Rule), which would reduce sulfur dioxide and nitrogen oxide emissions
from utility boilers located in 29 states, including Wisconsin, Michigan,
Pennsylvania, and New York. In March 2005, the EPA finalized both the mercury
rule and the Clean Air Interstate Rule.
The
final mercury
rule establishes New Source Performance Standards for new units based upon
the
type of coal burned. Weston 4 will install and operate mercury control
technology with the aim of achieving a mercury emission rate less than that
in
the final EPA mercury rule.
The
final mercury
rule also establishes a mercury cap and trade program, which requires a 21%
reduction in national mercury emissions in 2010 and a 70% reduction in national
mercury emissions beginning in 2018. Based on the final rule and current
projections, WPSC anticipates meeting the mercury rule cap and trade
requirements at a cost similar to the cost to comply with the Wisconsin
rule.
PDI's
current
analysis indicates that additional emission control equipment on its existing
units may be required. Excluding Sunbury, PDI estimates the capital cost
for the
remaining units to be approximately $1 million to achieve a 70% reduction.
Including Sunbury, the total PDI mercury control costs could approximate
$33 million, depending upon how this facility is operated.
The
final Clean Air
Interstate Rule requires reduction of sulfur dioxide and nitrogen oxide
emissions in two phases. The first phase requires about a 50% reduction
beginning in 2009 for nitrogen oxide and beginning in 2010 for sulfur dioxide.
The second phase begins in 2015 for both pollutants and requires about a
65%
reduction in emissions. The rule allows the affected states (including
Wisconsin, Michigan, Pennsylvania, and New York) to either require utilities
located in the state to participate in the EPA's interstate cap and trade
program or meet the state's emission budget for sulfur dioxide and nitrogen
oxide through measures to be determined by the state. The states have not
adopted a preference as to which option they would select, but the states
are
investigating the cap and trade program, as well as alternatives or additional
requirements. Consequently, the effect of the rule on WPSC's and PDI's
facilities is uncertain, since it depends upon how the states choose to
implement the final Clean Air Interstate Rule.
Currently,
WPSC is
evaluating a number of options that include using the cap and trade program
and/or installing controls. For planning purposes, it is assumed that additional
sulfur dioxide and nitrogen oxide controls will be needed on existing units
or
the existing units will need to be converted to natural gas by 2015. The
installation of any controls and/or any conversion to natural gas will need
to
be scheduled as part of WPSC's long-term maintenance plan for its existing
units. As such, controls or conversions may need to take place before 2015.
On a
preliminary basis and assuming controls or conversion are required, WPSC
estimates capital costs of $257 million in order to meet an assumed 2015
compliance date. This estimate is based on costs of current control technology
and current information regarding the final EPA rule. The costs may change
based
on the requirements of the final state rules.
PDI
is evaluating
the compliance options for the Clean Air Interstate Rule. Additional nitrogen
oxide controls on some of PDI's facilities may be necessary, and would cost
approximately $41 million. The cost estimate is largely dependent upon how
Sunbury will be operated going forward. See Note 4, Assets
Held for
Sale,
for additional
information on Sunbury. Additional sulfur dioxide reductions are unlikely.
Also,
PDI will evaluate a number of options including using the cap and trade program,
fuel switching, and/or installing controls.
Clean
Air
Regulations
Most
of the
generation facilities owned by PDI are located in an ozone transport region.
As
a result, these generation facilities are subject to additional restrictions
on
emissions of nitrogen oxide. Throughout 2005 and in future years, PDI estimates
purchasing nitrogen oxide emission allowances at market rates, as needed,
to
meet its requirements for the Sunbury generation facility.
PDI
began 2005 with
17,000 sulfur dioxide emission allowances for its generation facilities that
are
required to participate in the sulfur dioxide emission program. However,
a
majority of these allowances were sold in the second quarter of 2005, requiring
a higher level of purchases for the remainder of the year. During the remainder
of 2005 and in future years, PDI estimates purchasing sulfur dioxide allowances
at market rates, as needed, to meet its requirements for the Sunbury generation
facility.
Other
Environmental Issues
Groundwater
testing
at a former ash disposal site of UPPCO indicated elevated levels of boron
and
lithium. Supplemental remedial investigations were performed, and a revised
remedial action plan was developed. The Michigan Department of Environmental
Quality approved the plan in January 2003. UPPCO received an order from the
MPSC
permitting deferral and future recovery of these costs. A liability of
$1.4 million and an associated regulatory asset of $1.4 million were
recorded for estimated future expenditures associated with remediation of
the
site. UPPCO has an informal agreement, with the owner of another landfill,
under
which UPPCO has agreed to pay 17% of the investigation and remedial costs.
It is
estimated that the cost of addressing the site over the next 3 years will
be
$1.6 million. UPPCO has recorded $0.3 million of this amount as its
share of the liability as of September 30, 2005.
Manufactured
Gas Plant Remediation
WPSC
continues to
investigate the environmental cleanup of ten manufactured gas plant sites.
Cleanup of the land portion of the Oshkosh, Stevens Point, Green Bay, Manitowoc,
and two Sheboygan sites is completed. Groundwater treatment and monitoring
at
these sites will continue into the future. Cleanup of the land portion of
four
sites will be addressed in the future. River sediment remains to be addressed
at
sites with sediment contamination, and priorities will be determined in
consultation with the EPA. In late 2004, WPSC purchased the Menominee site
property. Clean up of this site is expected to begin in the near future.
Work at
the other sites remains to be scheduled.
WPSC
is currently
in the process of transferring sites with sediment contamination formally
under
WDNR jurisdiction to the EPA Superfund Alternatives Program. Under the EPA's
program, the remedy decision will be based on risk-based criteria typically
used
at Superfund sites. WPSC estimated the future undiscounted investigation
and
cleanup costs as of September 30, 2005, to be $65.3 million. WPSC may
adjust these estimates in the future contingent upon remedial technology,
regulatory requirements, remedy determinations, and the assessment of natural
resource damages. WPSC has received $12.7 million to date in insurance
recoveries. WPSC expects to recover actual cleanup costs, net of insurance
recoveries, in future customer rates. Under current PSCW policies, WPSC will
not
recover carrying costs associated with the cleanup expenditures.
Stray
Voltage Claims
From
time to time,
WPSC has been sued by dairy farmers who allege that they have suffered loss
of
milk production and other damages supposedly due to "stray voltage" from
the
operation of WPSC's electrical system. Past cases have been resolved without
any
material adverse effect on the financial statements
of
WPSC. One case, Allen
v.
WPSC,
has been remanded
from the court of appeals to the trial court for a determination of whether
a
post-verdict injunction is warranted. A second case, Pollack
v.
WPSC,
was tried and
ended in a defense verdict on May 5, 2005, and that case is concluded. A
third
case, Seidl
v.
WPSC,
was tried to a
jury in October 2004, but ended in a mistrial. On June 21, 2005, the trial
judge
granted WPSC's motion for a directed verdict. The Seidl plaintiffs have filed
a
notice of appeal of that dismissal.
The
PSCW has
established certain requirements regarding stray voltage for all utilities
subject to its jurisdiction. The PSCW has defined what constitutes "stray
voltage," established a level of concern at which some utility corrective
action
is required, and set forth test protocols to be employed in evaluating whether
a
stray voltage problem exists. Based upon the information available to it
to
date, WPSC believes that it was in compliance with the PSCW's orders, and
the
plaintiffs did not have a stray voltage problem as defined by the PSCW for
which
WPSC is responsible. Nonetheless, in 2003, the Supreme Court of Wisconsin
ruled
in the case Hoffmann
v.
WEPCO
that a utility
could be liable in tort to a farmer for damage from stray voltage even though
the utility had complied with the PSCW's established level of
concern.
On
February 15, 2005, the Court of Appeals affirmed the jury verdict in
Allen
v.
WPSC,
which awarded the
plaintiff approximately $0.8 million for economic damages and
$1 million for nuisance. The Court of Appeals also remanded to the trial
court the issue of whether an injunction should be issued for additional
proceedings. The Supreme Court of Wisconsin denied WPSC's petition to review
the
Court of Appeals decision. The judgment has been paid to the plaintiff. The
trial judge must now decide whether an injunction should be issued. The expert
witnesses retained by WPSC do not believe that there is any scientific basis
for
concluding that electricity from the utility system is currently creating
any
problem on the plaintiff's land. Accordingly, WPSC does not believe there
is any
basis for issuing an injunction, and intends to vigorously contest the portion
of the case that will be remanded for further proceedings.
On
August 2, 2005, a judgment was entered dismissing the Seidls’ stray voltage case
and awarding WPSC its costs, which were approximately $63,000. On
September 14, 2005, the Seidls filed a notice of appeal from that judgment.
The appeal asserts that the trial court did not have jurisdiction to grant
the
motion to dismiss because of the passage of time, and that there was sufficient
evidence in the record that WPSC was negligent in distributing electricity
to
the Seidls to require a jury to resolve that issue. It typically takes about
a
year to resolve appeals. WPSC believes it has meritorious arguments which
support the judgment and plans to vigorously contest the appeal.
WPSC
has insurance
coverage for the pending claims, but the policies have customary self-insured
retentions per occurrence. Based upon the information known at this time
and the
availability of insurance, WPSC believes that the total cost to it of resolving
the two remaining actions will not be material.
Flood
Damage
On
May 14, 2003, a fuse plug at the Silver Lake reservoir owned by UPPCO was
breached. This breach resulted in subsequent flooding downstream on the Dead
River, which is located in Michigan's Upper Peninsula near Marquette, Michigan.
A
dam owned by Marquette Board of Light and Power, which is located downstream
from the Silver Lake reservoir near the mouth of the Dead River, also failed
during this event. In addition, high water conditions and siltation resulted
in
damage at the Presque Isle Power Plant owned by Wisconsin Electric Power
Company. Presque Isle, which is located downstream from the Marquette Board
of
Light and Power dam, was ultimately forced into a temporary shutdown.
The
FERC's
Independent Board of Review issued its report in December of 2003 and
concluded that the root cause of the incident was the failure of the design
of
the fuse plug to take into account the highly erodible nature of the fuse
plug's
foundation materials and spillway channel, resulting in the complete loss
of the
fuse plug, foundation, and spillway channel, which caused the release of
Silver
Lake far beyond the
intended
design of
the fuse plug. The fuse plug for the Silver Lake reservoir was designed by
an outside engineering firm.
UPPCO
has worked
with federal and state agencies in their investigations. UPPCO is still in
the
process of investigating the incident. WPS Resources maintains a
comprehensive insurance program that includes UPPCO and which provides both
property insurance for its facilities and liability insurance for liability
to
third parties. WPS Resources is insured in amounts that it believes are
sufficient to cover its responsibilities in connection with this event.
Deductibles and self-insured retentions on these policies are not material
to
WPS Resources.
As
of May 13, 2005, several lawsuits were filed by the claimants and putative
defendants relating to this incident. The suits that have been filed against
UPPCO, WPS Resources, and WPSC include the following claimants: WE Energies,
Cleveland Cliffs, Inc., Board of Light and Power of the City of Marquette,
the
City of Marquette, the County of Marquette, Dead River Campers, Inc., Marquette
County Road Commission, SBC, and various land and homeowners along the Silver
Lake reservoir and Dead River system. WPS Resources is defending these
lawsuits and is seeking resolution of all claims and litigation where
possible.
UPPCO
filed a suit
against the engineering company that designed the fuse plug (MWH Americas,
Inc.)
and the contractor who built it (Moyle Construction, Inc.).
In
November 2003, UPPCO received approval from the MPSC and the FERC for deferral
of costs that are not reimbursable through insurance or recoverable through
the
power supply cost recovery mechanism. Recovery of costs deferred will be
addressed in future rate proceedings.
In
January 2005, UPPCO announced its decision to restore Silver Lake as a reservoir
for power generation, pending approval of a design by FERC. FERC has required
that a board of consultants evaluate and oversee the new construction. The
board
of consultants is expected to review the design options in the fall of 2005,
prior to construction, with construction expected to be completed in
2006.
Wausau,
Wisconsin, to Duluth, Minnesota, Transmission Line
Construction
of the
220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota, transmission
line began in the first quarter of 2004 with the Minnesota portion completed
in
early 2005. Construction in Wisconsin began on August 8, 2005.
ATC
has assumed
primary responsibility for the overall management of the project and will
own
and operate the completed line. WPSC received approval from the PSCW and
the
FERC to transfer ownership of the project to ATC. WPSC will continue to manage
obtaining the private property rights, design, and construction of the Wisconsin
portion of the project.
In
December 2003, the PSCW issued an amended Certificate of Public Convenience
and Necessity per ATC's request for relief. This decision was appealed to
the
Dane County Circuit Court by certain landowners. The court affirmed the PSCW's
decision, and no appeal has been filed during the allowed time allotted for
appeals. On July 25, 2005, the Administrative Law Judge issued the WDNR permit
and water quality certification, subject to certain conditions. The conditions
were acceptable to ATC and WPSC. Project opponents did not file an appeal
of the
Administrative Law Judge’s decision within the specified time, and it too is
final. In addition, on August 5, 2005, the new law allowing condemnation
of
county land for transmission lines approved by the PSCW became effective.
In
light of this legislation, Douglas County negotiated an easement agreement
with
ATC that allows the project to be constructed across county land on the route
originally selected by the PSCW. On September 15, 2005, the County Board
approved that agreement. Accordingly, the lawsuit against Douglas County
to
force it to provide easements for the project is being dismissed as moot,
and
ATC has asked the PSCW to close the docket which was opened to examine
alternative routes in Douglas County.
WPS Resources
committed to fund 50% of total project costs incurred up to $198 million
and will receive additional equity in the ATC in exchange for the project
funding. Under its agreement to fund approximately half of the Wausau to
Duluth
transmission line, WPS Resources invested $35.4 million in the ATC for
the nine months ended September 30, 2005, bringing WPS Resources’
investment in the
ATC
related to the
project to $63.0 million since the inception of the project.
WPS Resources may terminate funding if the project extends beyond
January 1, 2010. On December 19, 2003, WPSC and ATC received approval
from the PSCW to continue the project at a revised cost estimate of
$420.3 million to reflect additional costs for the project resulting from
time delays, added regulatory requirements, changes and additions to the
project, and ATC overhead costs. WPS Resources has the right, but not the
obligation, to provide additional funding in excess of $198 million for up
to 50% of the revised cost estimate. The final portion of the line is expected
to be placed in service in 2008. Allete, Inc. has an option to fund a portion
of
this commitment and intends to fund $60 million by the end of 2006. This
would
ultimately decrease the amount of additional equity WPS Resources has in
the
ATC. For the period October 2005 through November 2008, WPS Resources expects
to
fund up to approximately $141 million for its portion of the Wausau to
Duluth transmission line assuming Allete, Inc. does not exercise its option,
and
approximately $81 million if Allete, Inc. does exercise this option.
Beaver
Falls
PDI's
Beaver Falls
generation facility in New York has been out of service since late
June 2005. An unplanned outage was caused by the failure of the first stage
turbine blades. At this time, inclusive of estimated insurance recoveries,
PDI
estimates that it will cost between $3 million and $5 million to repair the
turbine and replace the damaged blades. If the estimated repair costs are
subsequently revised upward or if the repair costs are not fully recoverable
through insurance, then a possibility exists that the repairs either will
not be
made or will cause the undiscounted cash flows related to future operations
to
be insufficient to recover the carrying value of the plant, resulting in
an
impairment. The carrying value of the Beaver Falls generation facility at
September 30, 2005, is $18.6 million.
Synthetic
Fuel Production Facility
We
have significantly reduced our consolidated federal income tax liability
for the
past four years through tax credits available to us under Section 29 of the
Internal Revenue Code for the production and sale of solid synthetic fuel
from
coal. These tax credits are scheduled to expire at the end of 2007 and are
provided as an incentive for taxpayers to produce fuels from alternate sources
and reduce domestic dependence on imported oil. This incentive is not deemed
necessary if the price of oil increases sufficiently to provide a natural
market
for these fuels. Therefore, the tax credit in a given year is subject to
phase
out if the reference price of oil within that year exceeds a threshold price
and
is eliminated entirely if the reference price increases beyond a phase-out
price. The reference price of a barrel of oil is an estimate of the annual
average wellhead price per barrel for domestic crude oil. The threshold price
at
which the credit begins to phase out was set in 1980 and is adjusted annually
for inflation. For 2004, the reference price was $36.75, the threshold price
was
$51.35, and the credits would have been eliminated had the reference price
exceeded $64.47. For 2005, the estimated threshold price is $52.57, and the
credits will be eliminated if the reference price exceeds $65.99.
Numerous
events
have recently increased domestic crude oil prices, including concerns about
terrorism, storm-related supply disruptions, and worldwide demand. Although
we
do not expect the amount of our 2005 Section 29 tax credits to be adversely
affected by oil prices given the current forward price curve for crude oil,
we
cannot predict with any certainty the future price of a barrel of oil.
Therefore, in order to manage exposure to the risk of an increase in oil
prices
that could reduce the amount of 2005, 2006, and 2007 Section 29 tax credits
that
could be recognized, PDI entered into a series of derivative contracts covering
a specified number of barrels of oil. These derivatives mitigate approximately
100%, 95%, and 40% of the Section 29 tax credit exposure in 2005, 2006, and
2007, respectively. The derivative contracts involve purchased and written
call
options that provide for net cash settlement at expiration based on the average
NYMEX trading price of oil in relation to the strike price of each option.
Our
ability to
fully utilize the Section 29 tax credits available to us in connection with
our
remaining interest in a synthetic fuel production facility will depend on
whether the amount of our federal income tax liability is sufficient to permit
the use of such credits. Other future tax legislation and Internal Revenue
Service review may also affect the value of the tax credits and the value
of our
share of the facility. In 2005, we recognized $24.1 million in Section 29
tax credits. At September 30, 2005, we determined that it was not necessary
to record a reserve against any portion of the deferred tax asset related
to
these
credits.
We have
recorded the tax benefit of approximately $133.3 million of Section 29
tax credits as reductions to income tax expense from the project's inception
in
June 1998 through September 30, 2005. As a result of alternative
minimum tax rules, approximately $71.6 million of this tax benefit has been
carried forward as a deferred tax asset as of September 30, 2005. These
alternative minimum tax credits can be carried forward indefinitely. The
tax
benefit recorded with respect to WPS Resources' share of tax credits from
the facility is based on our expected consolidated tax liability for all
open
tax years including the current year, and all future years in which we expect
to
utilize deferred tax credits to offset our future tax liability. Reductions
in
our expected consolidated tax liability for any of these years could result
in
disallowance of previously recorded credits, and/or a change in the amount
of
the tax benefit deferred to future periods.
A
portion of future payments under one of the agreements covering the sale
of a
portion of our interest in the facility is contingent on the facility's
continued production of synthetic fuel. In the event of a
Section
29 tax
credit phase-out in 2006 and 2007, a possibility exists that the level of
synthetic fuel production at the facility would be reduced. If the facility
reduces production, PDI may see an adjustment in the $7 million annual
pre-tax gains expected to be realized through 2007 from the sell-down.
Dairyland
Power Cooperative
Dairyland
Power
Cooperative has confirmed its intent to purchase a 30% interest in Weston
4 by
signing a joint plant agreement in November 2004, subject to a number of
conditions. The agreement with Dairyland Power Cooperative is part of our
continuing plan to provide least-cost, reliable energy for the increasing
electric demand of our customers. WPS Resources anticipates closing on the
agreement with Dairyland Power Cooperative by the end of 2005, at which time
Dairyland Power Cooperative will remit payment to WPSC in an amount equal
to 30%
of total costs already incurred by WPSC related to Weston 4 and thereafter
will fund 30% of future costs.
NOTE
12--EMPLOYEE BENEFIT PLANS
The
following table
provides the components of net periodic benefit cost for WPS Resources'
benefit plans for the three months ended September 30:
|
|
|
|
|
|
WPS Resources
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
6.0
|
|
$
|
5.2
|
|
$
|
2.0
|
|
$
|
1.8
|
|
Interest
cost
|
|
|
10.0
|
|
|
10.0
|
|
|
4.1
|
|
|
4.1
|
|
Expected
return on plan assets
|
|
|
(10.9
|
)
|
|
(11.5
|
)
|
|
(3.1
|
)
|
|
(2.9
|
)
|
Amortization
of transition obligation
|
|
|
-
|
|
|
-
|
|
|
0.1
|
|
|
0.1
|
|
Amortization
of prior-service cost (credit)
|
|
|
1.3
|
|
|
1.4
|
|
|
(0.6
|
)
|
|
(0.5
|
)
|
Amortization
of net loss
|
|
|
2.2
|
|
|
1.2
|
|
|
1.4
|
|
|
0.7
|
|
Net
periodic
benefit cost
|
|
$
|
8.6
|
|
$
|
6.3
|
|
$
|
3.9
|
|
$
|
3.3
|
|
WPSC's
share of net
periodic benefit cost for the three months ended September 30 is included
in the table below:
|
|
|
|
|
|
WPSC
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
4.8
|
|
$
|
4.2
|
|
$
|
1.9
|
|
$
|
1.6
|
|
Interest
cost
|
|
|
8.4
|
|
|
8.3
|
|
|
3.7
|
|
|
3.7
|
|
Expected
return on plan assets
|
|
|
(9.6
|
)
|
|
(10.2
|
)
|
|
(3.0
|
)
|
|
(2.8
|
)
|
Amortization
of transition obligation
|
|
|
-
|
|
|
-
|
|
|
0.1
|
|
|
0.1
|
|
Amortization
of prior-service cost (credit)
|
|
|
1.2
|
|
|
1.3
|
|
|
(0.5
|
)
|
|
(0.5
|
)
|
Amortization
of net loss
|
|
|
1.5
|
|
|
0.5
|
|
|
1.2
|
|
|
0.6
|
|
Net
periodic
benefit cost
|
|
$
|
6.3
|
|
$
|
4.1
|
|
$
|
3.4
|
|
$
|
2.7
|
|
The
following table
provides the components of net periodic benefit cost for WPS Resources'
benefit plans for the nine months ended September 30:
|
|
|
|
|
|
WPS Resources
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
17.9
|
|
$
|
15.4
|
|
$
|
6.0
|
|
$
|
5.7
|
|
Interest
cost
|
|
|
30.2
|
|
|
29.9
|
|
|
12.4
|
|
|
12.8
|
|
Expected
return on plan assets
|
|
|
(32.7
|
)
|
|
(34.4
|
)
|
|
(9.4
|
)
|
|
(8.7
|
)
|
Amortization
of transition obligation
|
|
|
0.1
|
|
|
0.1
|
|
|
0.3
|
|
|
0.3
|
|
Amortization
of prior-service cost (credit)
|
|
|
4.0
|
|
|
4.3
|
|
|
(1.6
|
)
|
|
(1.7
|
)
|
Amortization
of net loss
|
|
|
6.5
|
|
|
3.3
|
|
|
4.1
|
|
|
3.4
|
|
Net
periodic
benefit cost
|
|
$
|
26.0
|
|
$
|
18.6
|
|
$
|
11.8
|
|
$
|
11.8
|
|
WPSC's
share of net
periodic benefit cost for the nine months ended September 30 is included in
the table below:
|
|
|
|
|
|
WPSC
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
14.5
|
|
$
|
12.5
|
|
$
|
5.6
|
|
$
|
5.2
|
|
Interest
cost
|
|
|
25.1
|
|
|
24.9
|
|
|
11.3
|
|
|
11.5
|
|
Expected
return on plan assets
|
|
|
(28.7
|
)
|
|
(30.6
|
)
|
|
(9.1
|
)
|
|
(8.5
|
)
|
Amortization
of transition obligation
|
|
|
0.1
|
|
|
0.1
|
|
|
0.3
|
|
|
0.3
|
|
Amortization
of prior-service cost (credit)
|
|
|
3.6
|
|
|
3.8
|
|
|
(1.4
|
)
|
|
(1.4
|
)
|
Amortization
of net loss
|
|
|
4.3
|
|
|
1.6
|
|
|
3.5
|
|
|
2.6
|
|
Net
periodic
benefit cost
|
|
$
|
18.9
|
|
$
|
12.3
|
|
$
|
10.2
|
|
$
|
9.7
|
|
Contributions
to
the plans are made in accordance with legal and tax requirements and do not
necessarily occur evenly throughout the year. For the nine months ended
September 30, 2005, $8.2 million of contributions were made to the
pension benefit plan, and no contributions were made to the other postretirement
benefit plans. WPS Resources expects to contribute an additional
$20.4 million to its other postretirement benefit plans in
2005.
NOTE
13--STOCK-BASED COMPENSATION
WPS Resources
has four stock-based compensation plans: the 2005 Omnibus Incentive Compensation
Plan ("2005 Omnibus Plan"), the 2001 Omnibus Incentive Compensation Plan
("2001
Omnibus Plan"), the 1999 Stock Option Plan ("Employee Plan"), and the
1999 Non-Employee Directors Stock Option Plan ("Director Plan"). No
additional stock-based compensation will be issued under the 2001 Omnibus
Plan
or the Employee Plan, although the plans will continue to exist for purposes
of
the existing outstanding stock-based compensation.
WPS Resources
accounts for these plans under the recognition and measurement principles
of
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to
Employees," and related interpretations. Upon grant of stock options, no
stock-based employee compensation cost is reflected in net income, as all
options granted under these plans had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following
table
illustrates the effect on income available for common shareholders and earnings
per share if the company had applied the fair value recognition provisions
of
SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee
compensation:
|
|
|
|
|
|
|
|
Three
Months
Ended
September 30,
|
|
Nine
Months
Ended
September 30,
|
|
(Millions,
except per share amounts)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
Income
available for common shareholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported
|
|
$
|
48.2
|
|
$
|
34.8
|
|
$
|
138.0
|
|
$
|
82.0
|
|
Add:
Stock-based compensation expense
using
the intrinsic value method - net of tax
|
|
|
0.3
|
|
|
0.2
|
|
|
1.6
|
|
|
0.7
|
|
Deduct:
Stock-based compensation expense
using
the fair value method - net of tax
|
|
|
(0.4
|
)
|
|
(0.3
|
)
|
|
(1.1
|
)
|
|
(0.9
|
)
|
Pro
forma
|
|
$
|
48.1
|
|
$
|
34.7
|
|
$
|
138.5
|
|
$
|
81.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported
|
|
$
|
1.26
|
|
$
|
0.93
|
|
$
|
3.63
|
|
$
|
2.20
|
|
Pro
forma
|
|
|
1.26
|
|
|
0.93
|
|
|
3.64
|
|
|
2.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported
|
|
$
|
1.25
|
|
$
|
0.93
|
|
$
|
3.60
|
|
$
|
2.19
|
|
Pro
forma
|
|
|
1.25
|
|
|
0.92
|
|
|
3.62
|
|
|
2.18
|
|
NOTE
14--COMPREHENSIVE INCOME
SFAS
No. 130,
"Reporting Comprehensive Income," requires the reporting of other comprehensive
income in addition to income available for common shareholders. Total
comprehensive income includes all changes in equity during a period except
those
resulting from investments by shareholders and distributions to shareholders.
WPS Resources' total comprehensive income is:
|
|
|
|
|
|
Three
Months
Ended
September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Income
available for common shareholders
|
|
$
|
48.2
|
|
$
|
34.8
|
|
Cash
flow
hedges, net of tax of $(13.5) and $(1.0)
|
|
|
(21.3
|
)
|
|
(1.7
|
)
|
Foreign
currency translation
|
|
|
0.4
|
|
|
-
|
|
Unrealized
gain on available-for-sale securities, net of tax
|
|
|
0.5
|
|
|
-
|
|
Total
comprehensive income
|
|
$
|
27.8
|
|
$
|
33.1
|
|
|
|
|
|
|
|
Nine
Months
Ended
September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Income
available for common shareholders
|
|
$
|
138.0
|
|
$
|
82.0
|
|
Cash
flow
hedges, net of tax of $(20.5) and $5.2
|
|
|
(32.0
|
)
|
|
7.6
|
|
Foreign
currency translation
|
|
|
0.1
|
|
|
-
|
|
Unrealized
gain on available-for-sale securities, net of tax
|
|
|
0.6
|
|
|
-
|
|
Total
comprehensive income
|
|
$
|
106.7
|
|
$
|
89.6
|
|
The
following table
shows the changes to Accumulated Other Comprehensive Income from
December 31, 2004, to September 30, 2005.
(Millions)
|
|
|
|
December 31,
2004 balance
|
|
$
|
(16.1
|
)
|
Cash
flow
hedges
|
|
|
(32.0
|
)
|
Foreign
currency translation adjustment
|
|
|
0.1
|
|
Unrealized
gain on available-for-sale securities
|
|
|
0.6
|
|
September 30,
2005 balance
|
|
$
|
(47.4
|
)
|
NOTE
15--EARNINGS PER SHARE
|
|
|
|
|
|
WPS Resources'
common stock shares, $1 par value
|
|
September 30,
2005
|
|
December 31,
2004
|
|
Common
stock
outstanding, $1 par value, 200,000,000 shares authorized
|
|
|
38,091,465
|
|
|
37,500,791
|
|
Treasury
shares
|
|
|
12,000
|
|
|
12,000
|
|
Average
cost
of treasury shares
|
|
$
|
25.19
|
|
$
|
25.19
|
|
Shares
in
deferred compensation rabbi trust
|
|
|
267,794
|
|
|
229,238
|
|
Average
cost
of deferred compensation rabbi trust shares
|
|
$
|
40.13
|
|
$
|
36.84
|
|
Earnings
per share
is computed by dividing income available for common shareholders by the weighted
average number of shares of common stock outstanding during the period. Diluted
earnings per share is computed by dividing income available for common
shareholders by the weighted average number of shares of common stock
outstanding during the period adjusted for the exercise and/or conversion
of all
potentially dilutive securities. Such dilutive items include in-the-money
stock
options, restricted shares, and performance share grants. The calculation
of
diluted earnings per share for the years shown excludes some stock option
plan
shares that had an anti-dilutive effect. The shares having an anti-dilutive
effect are not significant for any of the periods shown. The following table
reconciles the computation of basic and diluted earnings per share:
|
|
|
|
|
|
Reconciliation
of Earnings Per Share
|
|
Three
Months
Ended
September 30,
|
|
Nine
Months
Ended
September 30,
|
|
(Millions,
except per share amounts)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Income
available to common shareholders
|
|
$
|
48.2
|
|
$
|
34.8
|
|
$
|
138.0
|
|
$
|
82.0
|
|
Basic
weighted average shares
|
|
|
38.2
|
|
|
37.4
|
|
|
38.0
|
|
|
37.2
|
|
Incremental
issuable shares
|
|
|
0.4
|
|
|
0.2
|
|
|
0.3
|
|
|
0.3
|
|
Diluted
weighted average shares
|
|
|
38.6
|
|
|
37.6
|
|
|
38.3
|
|
|
37.5
|
|
Basic
earnings per common share
|
|
$
|
1.26
|
|
$
|
0.93
|
|
$
|
3.63
|
|
$
|
2.20
|
|
Diluted
earnings per common share
|
|
$
|
1.25
|
|
$
|
0.93
|
|
$
|
3.60
|
|
$
|
2.19
|
|
NOTE
16--REGULATORY ENVIRONMENT
Wisconsin
On
November 5, 2004, WPSC filed an application with the PSCW to defer all
incremental costs, including carrying costs, resulting from unexpected problems
encountered in the 2004 refueling outage at Kewaunee. During the refueling
outage, an unexpected problem was encountered with equipment used for lifting
the reactor vessel internal components to perform a required 10-year inspection.
These equipment problems caused the outage to be extended by approximately
three
weeks. On November 11, 2004, the PSCW authorized WPSC to defer the replacement
fuel costs related to the extended outage. On November 23, 2004, the PSCW
authorized WPSC to defer purchased power costs ($5.6 million) and operating
and maintenance expenses ($1.6 million) related to the extended outage,
effective from when the problems were discovered, including carrying costs
at
WPSC's authorized weighted average cost of capital. Kewaunee returned to
service
on December 4, 2004. On February 18, 2005, WPSC filed for PSCW approval to
recover these costs. The PSCW is reviewing the costs associated with this
outage
and WPSC expects these costs to be addressed in the 2006 rate case, which
should
be settled in December 2005.
On
February 20, 2005, Kewaunee was temporarily removed from service after a
potential design weakness was identified in its auxiliary feedwater system.
Plant engineering staff identified the concern and the unit was shut down
in
accordance with the plant license. A modification was made to resolve the
issue
and the unit went back into service at 100% power on July 4, 2005. WPSC filed
a
request with the PSCW on March 11, 2005, for deferral of replacement power
and operating and maintenance expenses incurred to address the design weakness
and engineering issues identified. On March 17, 2005, the PSCW authorized
WPSC
to defer replacement fuel costs related to the outage. On April 8, 2005,
the
PSCW approved deferral of the operating and maintenance costs, including
carrying costs at the most
recently
authorized
pre-tax weighted average cost of capital. WPSC also filed with FERC for approval
to defer these costs in the wholesale jurisdiction. FERC is in the process
of
investigating the justness and reasonableness of the recovery of the costs
and
will subsequently rule on the filing. For our Michigan retail customers,
fuel
costs are recovered through a pass through fuel adjustment clause and no
deferral request is needed. Through July 4, 2005, WPSC had deferred
$46.2 million of replacement power costs and $11.6 million of
operating and maintenance expenses related to this outage. WPSC believes
recovery of these costs in future rates is probable and anticipates the PSCW
will address recovery of the deferred costs in the 2006 rate case. On July
5,
2005, WPSC sold its 59% share of Kewaunee to Dominion. See Note 5, Acquisitions
and Sales of Assets,
for further
information on the sale of Kewaunee.
As
part of the Kewaunee sale, the PSCW approved the refund of the value of the
nonqualified decommissioning trust fund to customers. The details of the
distribution of the refund will be addressed in the 2006 rate case. A proposal
to refund the nonqualified decommissioning trust fund to customers was also
approved by the FERC with no specification of the details for distribution.
Subsequently, on June 7, 2005, WPSC filed with the PSCW and FERC a request
for
establishment of a cooperative joint proceeding for approval of the Kewaunee
wind-up plan. The wind-up plan provides that the refunds to customers of
the
value of the nonqualified decommissioning trust fund be offset by the net
loss
on the sale of the plant and the Kewaunee related deferred costs applicable
to
each customer class. The wind-up plan also seeks to begin the amortization
of
the net regulatory liability as a credit to customer rates as of the effective
date of the PSCW’s order (expected to be January 1, 2006). On August 8, 2005,
the FERC accepted the proposed refund plan for filing and set it for hearing
and
settlement procedures; however, FERC denied the request for joint proceeding
with the PSCW. The PSCW plans to address these issues as part of the 2006
rate
case. FERC is holding a settlement discussion with WPSC in the fourth quarter
of
2005.
On
April 1, 2005, WPSC filed an application with the PSCW for an 11.4% increase
in
retail electric rates ($89.7 million in revenues) and a 2.09% increase in
natural gas rates ($10.0 million in revenues), both to be effective January
1, 2006. Factors driving the requested 2006 retail electric rate increase
include costs of transmission, costs for the construction of Weston 4, and
increased purchased power costs. The natural gas rate increase is primarily
related to increases in environmental monitoring costs and the cost of
distribution system improvements. These electric amounts do not include
adjustments for the nonqualified decommissioning trust fund, the loss on
the
sale of Kewaunee, or the Kewaunee outages, all of which are discussed
above.
On
October 6, 2005, WPSC updated the previously filed 2006 rate case application
with the PSCW for an additional 5.7% increase ($44.6 million increase in
revenues) to the electric generation fuel cost. The update to the rate case
is
due to the drastic increase in natural gas prices, including the effect of
production and supply disruptions in the Gulf of Mexico as a result of
Hurricanes Katrina and Rita. WPSC initially used 2006 natural gas futures
prices
from Fall 2004 to predict the 2006 cost of fuel for its natural gas-fired
electric generation facilities.
The
amount of fuel
and purchased power costs WPSC is authorized to recover in rates is established
in its PSCW general rate filings. If the actual fuel and purchased power
costs
vary from the authorized level by more than 2% on an annualized basis, WPSC
is
allowed, or may be required, to file an application adjusting rates for the
remainder of the year to reflect revised annualized cost estimates. At March
31,
2005, excluding the impact of the Kewaunee outage (which was deferred), WPSC
was
experiencing actual fuel and purchased power costs that were more than 2%
lower
than the currently approved level. As a result, on April 14, 2005, the PSCW
reopened WPSC's 2005 rate case for potential refund of fuel and purchased
power
costs. Therefore, revenues collected after that date were subject to refund
pending a review of projected fuel costs for 2005. Rates would be adjusted
downward for the balance of the year if projected costs were deemed to be
more
than 2% less than the amount allowed in the 2005 rate case. At June 30, 2005,
WPSC had recorded a refund liability of $2.1 million to reflect the
potential fuel refund due to customers. Subsequently, due to the drastic
increase in natural gas prices, projected fuel costs for 2005 are expected
to be
more than 2% higher than the currently approved level, and the $2.1 million
refund liability recorded in June was reversed during the third quarter of
2005.
WPSC
primarily
receives coal for all of its coal-fired plants from the Power River Basin
(PRB)
region in Wyoming. Delivery of coal from the PRB region has been disrupted
by
train derailments and other operational problems purportedly caused by
deteriorated rail track beds of approximately 100 miles in length in Wyoming.
Repair and reconstruction of the rail line, jointly owned by BNSF Railway
Co.
and Union Pacific Railroad, is expected to extend until December 1, 2005
with remaining repairs completed in the Spring of 2006. Coal shipments and
rail
operations are expected to return to normal levels when construction activity
is
halted in December; however, deliveries may be delayed again in the Spring
of
2006 as construction activity resumes. Reduced shipments of coal from Wyoming
mines in the PRB will reduce PRB coal available for WPSC generating facilities.
WPSC implemented a mitigation plan to conserve existing coal supplies and
to
obtain additional coal supplies from sources other than the PRB. The mitigation
plan is resulting in increased incremental fuel and purchased power costs
for
WPSC. Therefore, on September 9, 2005, WPSC requested authorization to
defer all incremental fuel and purchased power costs incurred, including
carrying costs at WPSC’s most recent authorized pre-tax weighted cost of
capital, as a result of the railroads’ reduction in coal deliveries and the
actions taken by WPSC to manage coal supplies in this emergency situation.
On
September 23, 2005, the PSCW approved WPSC’s request for deferred treatment
of the incremental fuel costs. As of September 30, 2005, $4.1 million
was deferred.
On
September 21, 2005, WPSC announced the acquisition of the Michigan and
Minnesota natural gas distribution operations of Aquila, Inc. (Aquila). See
Note
5, Acquisitions
and Sales of Assets,
for further
information on the acquisition of these assets. In relation to the acquisition,
WPS Michigan Utilities, Inc. and Aquila jointly filed with the MPSC on October
10, 2005, for approval of the termination of Aquila’s duty to provide natural
gas service in Michigan and for WPS Michigan Utilities to provide natural
gas
service in the Michigan service territory of Aquila pursuant to the rates,
terms, and conditions in Aquila’s current tariff book. Also in relation to the
acquisition, on October 17, 2005, WPS Minnesota Utilities, Inc. and Aquila
jointly filed with the Minnesota Public Utilities Commission to approve the
sale
of the Minnesota assets of Aquila’s two divisions, Aquila Networks-PNG and
Aquila Networks-NMU, to WPS Minnesota Utilities pursuant to the Asset
Purchase Agreement dated September 21, 2005. The MPSC and the Minnesota
Public Utilities Commission have not yet ruled on the filings.
Michigan
On
December 8, 2004, UPPCO submitted a request to the MPSC to approve UPPCO's
proposed treatment of the pre-tax gains from certain sales of undeveloped
and
partially developed land located in the Upper Peninsula of Michigan as
appropriate for ratemaking purposes. On February 4, 2005, UPPCO submitted
an
application to the MPSC for a 7.6% increase in retail electric rates
($5.7 million in revenues). UPPCO also requested interim rate recovery of
6.0% ($4.5 million in revenues) to allow UPPCO to recover costs during the
time the MPSC is reviewing the full case. The retail electric rate increase
was
required due to costs associated with improving service quality and reliability,
technology upgrades, and managing rising employee and retiree benefit costs.
On
April 28, 2005, the MPSC issued an order authorizing UPPCO to retain 100%
of the
pre-tax gains on certain lands owned up to $18.5 million and 73% of any
pre-tax gains over that amount and UPPCO withdrew the rate increase request.
In
addition, UPPCO will voluntarily forego filing for retail electric service
base
rate increases until January 1, 2006, except UPPCO may file for MPSC
consideration of deferred accounting of any governmental mandates during
the
moratorium and for any unusual and extraordinary events that would cause
serious
financial harm to UPPCO. Further, UPPCO's Power Supply Cost Recovery Clause
is
not subject to the filing moratorium. UPPCO intends to file a 2006 rate case
with the MPSC.
Federal
Through
a series of
orders issued by FERC, Regional Through and Out Rates for transmission service
between the MISO and the PJM Interconnection were eliminated effective
December 1, 2004. To compensate transmission owners for the revenue they
will no longer receive due to this elimination, FERC ordered a transitional
pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to
be
put into place, which will be paid by load serving entities. On February
10,
2005, FERC issued an order requesting compliance filings from transmission
providers implementing the SECA effective December 1, 2004, subject to
refund and surcharge, as appropriate. Public hearings will be held
regarding
the
compliance filings. The application and legality of the SECA is being challenged
by many load-serving entities, including ESI. On February 28, 2005, ESI
filed a motion for a Partial Stay of the February 10, 2005, FERC order,
proposing that SECA charges on its Michigan load be postponed until a FERC
order
approves a decision or settlement in the formal hearing proceeding. FERC
denied
this motion on May 4, 2005. On June 3, 2005, ESI filed with FERC a request
for rehearing of the order denying stay. ESI also participated in a joint
petition to the District of Columbia Circuit Court in an attempt to obtain
a final order from the FERC on rehearing of the initial SECA order. ESI will
continue to pursue all avenues to appeal and/or reduce the SECA obligations.
In
the interim, the exposure will be managed through customer charges and other
available avenues, where feasible. Resolution of issues to be raised in the
SECA
hearing offer the possibility of further reductions in ESI's exposure, but
the
extent is unknown at present. Through existing contracts, ESI has the ability
to
pass a portion of the SECA charges on to customers and has begun to do so.
Since
SECA is a transition charge ending on March 31, 2006, it does not directly
impact ESI's long-term competitiveness.
The
SECA is also an
issue for WPSC and UPPCO, who have intervened and protested a number of
proposals in this docket because those proposals could result in unjust,
unreasonable, and discriminatory charges for customers. It is anticipated
that
most of the SECA charges incurred by WPSC and UPPCO and any refunds will
be
passed on to customers through rates.
NOTE
17--SEGMENTS OF BUSINESS
We
manage our reportable segments separately due to their different operating
and
regulatory environments. Our utility business segments are the regulated
electric utility operations of WPSC and UPPCO and the regulated gas utility
operations of WPSC. Our other reportable segments include two nonregulated
companies, ESI and PDI. ESI is a diversified energy supply and services company.
PDI is an electric generation company. The Other segment includes the operations
of WPS Resources and WPS Resources Capital Corporation as holding
companies, along with the nonutility activities at WPSC and UPPCO.
|
|
Regulated
Utilities
|
|
Nonutility
and Nonregulated Operations
|
|
|
|
|
|
Segments
of Business
(Millions)
|
|
Electric
Utility(1)
|
|
Gas
Utility(1)
|
|
Total
Utility(1)
|
|
ESI
|
|
PDI
|
|
Other(1)
|
|
Reconciling
Eliminations
|
|
WPS Resources
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
289.6
|
|
$
|
71.6
|
|
$
|
361.2
|
|
$
|
1,328.8
|
|
$
|
67.3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,757.3
|
|
Intersegment
revenues
|
|
|
9.0
|
|
|
0.2
|
|
|
9.2
|
|
|
12.1
|
|
|
10.5
|
|
|
0.3
|
|
|
(32.1
|
)
|
|
-
|
|
Income
available for common shareholders
|
|
|
28.0
|
|
|
(3.5
|
)
|
|
24.5
|
|
|
8.9
|
|
|
13.2
|
|
|
1.6
|
|
|
-
|
|
|
48.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
September 30,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
233.5
|
|
$
|
45.5
|
|
$
|
279.0
|
|
$
|
782.4
|
|
$
|
30.5
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,091.9
|
|
Intersegment
revenues
|
|
|
5.5
|
|
|
0.1
|
|
|
5.6
|
|
|
(2.9
|
)
|
|
8.4
|
|
|
0.3
|
|
|
(11.4
|
)
|
|
-
|
|
Income
available for common shareholders
|
|
|
32.1
|
|
|
(3.3
|
)
|
|
28.8
|
|
|
2.5
|
|
|
4.2
|
|
|
(0.7
|
)
|
|
-
|
|
|
34.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
757.9
|
|
$
|
335.7
|
|
$
|
1,093.6
|
|
$
|
3,338.7
|
|
$
|
139.4
|
|
$
|
-
|
|
$
|
-
|
|
$
|
4,571.7
|
|
Intersegment
revenues
|
|
|
25.0
|
|
|
0.5
|
|
|
25.5
|
|
|
18.4
|
|
|
27.8
|
|
|
0.9
|
|
|
(72.6
|
)
|
|
-
|
|
Income
available for common shareholders
|
|
|
72.4
|
|
|
8.6
|
|
|
81.0
|
|
|
25.3
|
|
|
28.7
|
|
|
3.0
|
|
|
-
|
|
|
138.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
September 30,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
657.1
|
|
$
|
284.5
|
|
$
|
941.6
|
|
$
|
2,518.0
|
|
$
|
78.8
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,538.4
|
|
Intersegment
revenues
|
|
|
15.6
|
|
|
4.3
|
|
|
19.9
|
|
|
4.3
|
|
|
19.7
|
|
|
0.9
|
|
|
(44.8
|
)
|
|
-
|
|
Income
available for common shareholders
|
|
|
60.2
|
|
|
9.9
|
|
|
70.1
|
|
|
16.7
|
|
|
(5.0
|
)
|
|
0.2
|
|
|
-
|
|
|
82.0
|
|
|
(1)
Includes only utility operations. Nonutility operations are included
in
the Other column.
|
WPSC's
principal
business segments are the regulated electric utility operations and the
regulated gas utility operations.
|
|
Regulated
Utilities
|
|
|
|
|
|
|
|
Segments
of Business
(Millions)
|
|
Electric
Utility(1)
|
|
Gas
Utility(1)
|
|
Total
Utility
|
|
Other
|
|
Reconciling
Eliminations
|
|
WPSC
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
266.7
|
|
$
|
71.8
|
|
$
|
338.5
|
|
$
|
0.4
|
|
$
|
(0.4
|
)
|
$
|
338.5
|
|
Earnings
on
common stock
|
|
|
26.7
|
|
|
(3.5
|
)
|
|
23.2
|
|
|
2.6
|
|
|
(0.1
|
)
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
September 30,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
214.6
|
|
$
|
45.6
|
|
$
|
260.2
|
|
$
|
0.4
|
|
$
|
(0.4
|
)
|
$
|
260.2
|
|
Earnings
on
common stock
|
|
|
31.5
|
|
|
(3.3
|
)
|
|
28.2
|
|
|
2.3
|
|
|
-
|
|
|
30.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
705.8
|
|
$
|
336.2
|
|
$
|
1,042.0
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,042.0
|
|
Earnings
on
common stock
|
|
|
69.7
|
|
|
8.6
|
|
|
78.3
|
|
|
6.3
|
|
|
-
|
|
|
84.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
September 30,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
603.2
|
|
$
|
288.8
|
|
$
|
892.0
|
|
$
|
1.1
|
|
$
|
(1.1
|
)
|
$
|
892.0
|
|
Earnings
on
common stock
|
|
|
58.1
|
|
|
9.9
|
|
|
68.0
|
|
|
6.9
|
|
|
-
|
|
|
74.9
|
|
(1)
|
Includes
only
utility operations. Nonutility
operations are included in the Other
column.
|
NOTE
18--NEW ACCOUNTING PRONOUNCEMENTS
In
December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment," which
addresses the accounting for share-based payment transactions. SFAS No. 123R
eliminates the ability to account for share-based compensation transactions
using APB Opinion No. 25, "Accounting for Stock Issued to Employees," and
requires companies to measure the cost of share-based awards at the grant
date
fair value. That cost is recognized over the period during which an employee
is
required to provide service in exchange for the award. SFAS No. 123R will
be
effective for WPS Resources on January 1, 2006. SFAS No. 123R offers
companies alternative methods of adopting this standard. The impact on
WPS Resources' financial position and results of operations will be
dependent upon a number of factors, including share-based payments made in
2006.
Because we do not know the amount of share-based payments to be made in 2006,
we
cannot yet estimate the effect of this standard on our financial position
and
results of operations.
In
March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations." Interpretation No. 47 clarifies
that
the term Conditional Asset Retirement Obligation as used in FASB Statement
No.
143, "Accounting for Asset Retirement Obligations,"
refers to a legal
obligation to perform an asset retirement activity in which the timing and/or
method of settlement are conditional on a future event that may or may not
be
within the control of the entity. Accordingly, an entity is required to
recognize a liability for the fair value of a Conditional Asset Retirement
Obligation if the fair value of the liability can be reasonably estimated.
WPS Resources is required to adopt the provisions of Interpretation No. 47
as of December 31, 2005. WPS Resources has not yet determined the
impact that the adoption of Interpretation No. 47 will have on its financial
position or results of operations. If expenses under Interpretation No. 47
for
WPSC and UPPCO differ from expenses recovered currently in rates, management
will assess the probability of recovering this difference in future rates.
To
the extent future recovery is probable, a regulatory asset would be recognized
in accordance with the provisions of SFAS No. 71.
Item
2. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
INTRODUCTION
- WPS RESOURCES
WPS Resources
is a holding company that is exempt from the Public Utility Holding Company
Act
of 1935. Our wholly owned subsidiaries include two regulated utilities, WPSC
(which is an operating entity as well as a holding company exempt from the
Public Utility Holding Company Act of 1935) and UPPCO. Another wholly owned
subsidiary, WPS Resources Capital Corporation, is a holding company for our
nonregulated businesses, including ESI and PDI.
Strategic
Overview
The
focal point of
WPS Resources' business plan is the creation of long-term value for our
shareholders (through growth, operational excellence, and asset management)
and
the continued emphasis on reliable, competitively priced, and environmentally
sound energy services for our customers. We are seeking growth of our utility
and nonregulated portfolio, but we are placing emphasis on regulated
growth.
A discussion of
the essential components of our business plan is set forth below:
Maintain
a Strong Utility Base
-
We
are focusing on
growth in our utility operations. A strong utility base is important in
order to maintain quality credit ratings, which are critical to our success.
WPS Resources believes the following recent events have helped or will help
maintain its strong utility base:
· |
In
2004, WPSC
signed power sales contracts with Consolidated Water Power through
December 31, 2017, and Wisconsin Public Power Inc. through April 30,
2021, in order to bolster growth beyond the normal utility growth
rate.
|
· |
WPSC
is also
expanding its generation fleet in order to meet growing electric
demand
and ensure the continued reliability of energy services. Construction
is
underway on the 500-megawatt coal-fired Weston 4 base-load power
plant
near Wausau, Wisconsin. WPSC also continues to pursue plans to
construct
other electric generating facilities, but details relating to fuel
type
and in-service dates have yet to be
determined.
|
· |
In
September 2005, WPS Resources entered into a definitive
agreement with Aquila, Inc. to acquire Aquila's natural gas distribution
operations in Michigan and Minnesota. Subject to various regulatory
approvals, these transactions are expected to close in the first
half of
2006 and will more than double the size of WPS Resource's current
utility natural gas business.
|
· |
WPS
Resources
currently owns approximately 28% of ATC, which is a utility operation
that
owns, builds, maintains, and operates high voltage electric transmission
lines primarily in Wisconsin and Upper Michigan. We continue to
increase
our ownership interest in the ATC through additional equity interest
received as consideration for funding a portion of the Duluth,
Minnesota,
to Wausau, Wisconsin, transmission line.
|
Integrate
Resources to Provide Operational Excellence
-
WPS Resources
is committed to integrating the resources of its business units (in accordance
with any applicable regulatory restrictions) by leveraging their individual
capabilities and expertise across the company.
· |
This
strategy
is evident at our nonregulated subsidiaries, where we have restructured
the management of our two primary nonregulated subsidiaries (ESI
and PDI).
Currently, we have one executive management team overseeing the
operations
of all of our nonregulated businesses. ESI also continues to optimize
the
value of PDI's merchant generation fleet and reduce the market
price risk
while extracting additional value from these plants, through the
use of
various financial and physical instruments (such as forwards, futures,
options, and swaps), which has provided more predictable revenues
and
margin.
|
· |
Combining
resources and best practices of WPSC and the Aquila natural gas
distribution businesses in Michigan and Minnesota (expected to
be acquired
in 2006) is expected to enhance operations of our overall natural
gas
distribution businesses.
|
Strategically
Grow Nonregulated Businesses
-
ESI
looks to grow
its electric and natural gas business, targeting growth in the northeastern
United States and adjacent portions of Canada (through strategic
acquisitions, market penetration of existing businesses, and new product
offerings), which is where ESI has the most market expertise. PDI focuses
on
optimizing the operational efficiency of its existing portfolio of assets
and
pursues compatible power development projects and the acquisition of generation
assets that strategically fit with ESI's customer base and market expertise.
The
acquisition of Advantage Energy in July 2004 provided ESI with enhanced
opportunities to compete in the New York market and had a positive impact
on
ESI's margin in the first half of 2005.
Place
Strong Emphasis on Asset Management
-
Our
asset
management strategy calls for the continuing disposition and acquisition
of
assets in a manner that enhances our earnings capability. The acquisition
portion of this strategy calls for the acquisition of assets that complement
our
existing businesses and strategy, such as the pending acquisitions of Aquila's
natural gas distribution operations in Michigan and Minnesota, which are
expected to be accretive to earnings (excluding one-time transition costs)
over
the first 12 months following the close of the acquisition, as well as ESI's
2004 acquisition of Advantage Energy. The utilities are the backbone of our
earnings, and we expect ESI and PDI to continue to provide between 15 and
25
percent of our earnings in the future.
Another
portion of
the strategy calls for the disposition of assets, including plants and entire
business units, which are no longer required for operations. The sale of
Sunbury's allocated emission allowances was completed in May 2005 for
$109.9 million. The proceeds received from the sale enabled Sunbury to
eliminate its non-recourse debt obligation, which provided greater flexibility
as PDI evaluates its options related to Sunbury. These options range from
closing the plant, operating the plant only during favorable economic periods,
to a future sale. We also sold WPSC's Kewaunee plant in July 2005. The major
benefits of the Kewaunee sale include transferring financial risk from WPSC's
electric customers and WPS Resources' shareholders to Dominion, greater
certainty of future energy costs through a purchase power agreement, and
being
able to return the non-qualified decommissioning funds to our customers.
We
also continue to evaluate alternatives for the sale of the balance of our
identified real estate holdings no longer needed for operation. A significant
portion of our expected land sales are at UPPCO and will benefit our customers
as well as our shareholders. UPPCO withdrew a rate increase request that
it
filed in February 2005 after the MPSC approved its requested regulatory
treatment of these land sales by sharing gains between customers and
shareholders.
Business
Operations
Our
regulated and
nonregulated businesses have distinct competencies and business strategies,
offer differing products and services, experience a wide array of risks and
challenges and are viewed uniquely by management. The Management's
Discussion and Analysis of Financial Condition and Results of Operations
-
Introduction - WPS Resources
appearing in the
2004 Form 10-K included a discussion of these topics. There have not been
significant changes to the content of the matters discussed in the above
referenced section of the 2004 Form 10-K; however, certain tables have been
updated and included below to reflect current information. These tables should
be read in conjunction with the discussion appearing in Management's
Discussion and Analysis of Financial Condition and Results of Operations
-
Introduction - WPS Resources
appearing in the
2004 Form 10-K.
The
table below
discloses future natural gas and electric sales volumes under contract at
ESI as
of September 30, 2005. Contracts are generally one to three years in
duration. ESI expects that its ultimate sales volumes in 2005 and beyond
will
exceed the volumes shown in the table below as it continues to seek growth
opportunities and existing customers who do not have long-term contracts
continue to buy their short-term requirements from ESI.
|
|
|
|
|
|
Forward
Contracted Volumes at September 30, 2005 (1)
|
|
October
1, 2005
through
September 30,
2006
|
|
October
1, 2006
through
September 30,
2008
|
|
|
|
|
|
|
|
Wholesale
sales volumes - billion cubic feet
|
|
|
115.8
|
|
|
12.3
|
|
Retail
sales
volumes - billion cubic feet
|
|
|
151.1
|
|
|
47.0
|
|
Total
natural
gas sales volumes
|
|
|
266.9
|
|
|
59.3
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - million kilowatt-hours
|
|
|
10,951
|
|
|
4,803
|
|
Retail
sales
volumes - million kilowatt-hours
|
|
|
2,374
|
|
|
751
|
|
Total
electric sales volumes
|
|
|
13,325
|
|
|
5,554
|
|
(1) This
table
represents physical sales contracts for natural gas and electric power for
delivery or settlement in future periods; however, there is a possibility
that
some of the contracted volumes reflected in the above table could be net
settled. Management has no reason to believe that gross margins that will
be
generated by the contracts included above will vary significantly from those
experienced historically.
For
comparative
purposes, future natural gas and electric sales volumes under contract at
September 30, 2004, are shown below. Actual electric and natural gas sales
volumes for the nine months ended September 30, 2005, and 2004 are
disclosed within Results
of
Operations - WPS Resources, ESI Segment Operations
below.
|
|
|
|
|
|
Forward
Contracted Volumes at September 30, 2004 (1)
|
|
October
1,
2004
through
September 30,
2005
|
|
October
1,
2005
through
September 30,
2007
|
|
|
|
|
|
|
|
Wholesale
sales volumes - billion cubic feet
|
|
|
91.3
|
|
|
13.6
|
|
Retail
sales
volumes - billion cubic feet
|
|
|
162.9
|
|
|
48.9
|
|
Total
natural
gas sales volumes
|
|
|
254.2
|
|
|
62.5
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - million kilowatt-hours
|
|
|
5,523
|
|
|
1,032
|
|
Retail
sales
volumes - million kilowatt-hours
|
|
|
3,730
|
|
|
1,832
|
|
Total
electric sales volumes
|
|
|
9,253
|
|
|
2,864
|
|
(1) This
table
represents physical sales contracts for natural gas and electric power for
delivery or settlement in future periods; however, there is a possibility
that
some of the contracted volumes reflected in the above table could be net
settled. Management has no reason to believe that gross margins that will
be
generated by these contracts will vary significantly from those experienced
historically.
The
table below
summarizes ESI's wholesale counterparty credit exposure, categorized by maturity
date, as of September 30, 2005. At September 30, 2005, ESI had net
exposure with one non-rated counterparty that was more than 10% of total
exposure, including collateral. Total exposure with this counterparty was
$41.2
million and is included in the table below.
|
|
|
|
|
|
|
|
|
|
Counterparty
Rating (Millions)
(1)
|
|
Exposure
(2)
|
|
Exposure
Less
Than
1
Year
|
|
Exposure
1
to
3
Years
|
|
Exposure
4
to
5
years
|
|
|
|
|
|
|
|
|
|
|
|
Investment
grade - regulated utility
|
|
$
|
13.7
|
|
$
|
13.7
|
|
$
|
-
|
|
$
|
-
|
|
Investment
grade - other
|
|
|
305.0
|
|
|
223.8
|
|
|
76.0
|
|
|
5.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment
grade - regulated utility
|
|
|
32.2
|
|
|
32.2
|
|
|
-
|
|
|
-
|
|
Non-investment
grade - other
|
|
|
4.9
|
|
|
4.9
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-rated
-
regulated utility (3)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Non-rated
-
other (3)
|
|
|
97.1
|
|
|
85.4
|
|
|
10.3
|
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Exposure
|
|
$
|
452.9
|
|
$
|
360.0
|
|
$
|
86.3
|
|
$
|
6.6
|
|
(1)
The
investment and
non-investment grade categories are determined by publicly available credit
ratings of the counterparty or the rating of any guarantor, whichever is
higher.
Investment grade counterparties are those with a senior unsecured Moody's
rating
of Baa3 or above or a Standard & Poor's rating of BBB- or above.
(2)
|
Exposure
considers netting of accounts receivable and accounts payable where
netting agreements are in place as well as netting mark-to-market
exposure. Exposure is before consideration of collateral from
counterparties. Collateral, in the form of cash and letters of
credit,
received from counterparties totaled $68.4 million at
September 30, 2005, $63.0 million from investment grade
counterparties, and $5.4 million from non-rated
counterparties.
|
(3)
Non-rated
counterparties include stand-alone companies, as well as unrated subsidiaries
of
rated companies without parental credit support. These counterparties are
subject to an internal credit review process.
RESULTS
OF
OPERATIONS - WPS RESOURCES
Third
Quarter 2005 Compared with Third Quarter 2004
WPS Resources
Overview
WPS Resources'
results of operations for the three months ended September 30 are shown in
the following table:
|
|
|
|
|
|
|
|
WPS Resources'
Results
(Millions,
except share amounts)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Consolidated
operating revenues
|
|
$
|
1,757.3
|
|
$
|
1,091.9
|
|
|
60.9
|
%
|
Income
available for common shareholders
|
|
$
|
48.2
|
|
$
|
34.8
|
|
|
38.5
|
%
|
Basic
earnings per share
|
|
$
|
1.26
|
|
$
|
0.93
|
|
|
35.5
|
%
|
Diluted
earnings per share
|
|
$
|
1.25
|
|
$
|
0.93
|
|
|
34.4
|
%
|
The
$665.4 million increase in consolidated operating revenues for the quarter
ended September 30, 2005, compared to the same quarter in 2004, was driven
by a $561.4 million (72.0%) increase in revenue at ESI, an
$85.8 million (30.1%) increase in utility revenue, and a $38.9 million
(100.0%) increase in PDI revenue. Higher revenue at ESI was driven by an
increase in natural gas prices, continued expansion of the Canadian natural
gas
business, and higher volumes related to an increase in structured wholesale
natural gas transactions. Electric utility revenue increased $59.6 million,
primarily due to higher electric sales volumes related to warmer summer weather
conditions and new power sales agreements with wholesale customers, and an
approved retail electric rate increase. Gas utility revenue increased
$26.2 million due to an increase in the per-unit cost of natural gas,
higher natural gas throughput volumes, and an approved rate increase. The
increase in revenue at PDI was driven by higher revenue at Sunbury due to
increased opportunities to sell power into the market due to the expiration
of a
fixed price outtake contract and mark-to-market gains on derivatives utilized
to
protect the value of a portion of PDI's Section 29 federal tax credits. Revenue
changes by reportable segment are discussed in more detail below.
Income
available
for common shareholders was $48.2 million ($1.26 basic earnings per share)
for the quarter ended September 30, 2005, compared to $34.8 million
($0.93 basic earnings per share) for the same quarter in 2004. Significant
factors impacting the change in earnings and earnings per share are as follows
(and are discussed in more detail below).
· |
PDI's
earnings increased $9.0 million during the quarter ended
September 30, 2005, compared to the quarter ended September 30,
2004. The increase in PDI's earnings can be attributed to mark-to-market
and realized gains on derivative instruments utilized to protect
a portion
of PDI's Section 29 federal tax credits and significant improvements
in
Sunbury's margin, partially offset by a decrease in Section 29
federal tax
credits recognized during the
quarter.
|
· |
ESI's
earnings increased $6.4 million, driven by a $22.1 million
improvement in its natural gas margin during the quarter ended
September 30, 2005, compared to the same quarter in the prior year.
ESI's electric margin decreased $6.9 million, driven by lower margin
from
portfolio optimization strategies and lower margin from retail
electric
operations in Michigan. Partially offsetting the overall margin
improvement was a $5.7 million increase in ESI's operating and
maintenance
expenses related to continued business expansion.
|
· |
Utility
earnings decreased $4.3 million (14.9%), largely due to the negative
impact that increasing natural gas prices had on third quarter
margin at
the electric utility. Earnings were also negatively impacted because
certain costs incurred in the third quarter of 2005 related to
plant
outages, carrying costs on capital additions, and other costs (which
are
recovered in rates relatively evenly throughout the year) were
partially
recovered in revenue during the first six months of the year, leading
to
higher earnings in those periods.
|
· |
A
$2.6
million pre-tax increase (approximately $1.6 million after taxes)
in
equity earnings from our investment in the ATC also contributed
to the
increase in income available for common
shareholders.
|
Overview
of
Utility Operations
Utility
operations
include the electric utility segment, consisting of the electric operations
of
WPSC and UPPCO, and the gas utility segment, consisting of the natural gas
operations of WPSC. Income
available
for common shareholders attributable to the electric utility segment was
$28.0 million for the quarter ended September 30, 2005, compared to
$32.1 million for the quarter ended September 30, 2004. The net loss
attributable to the gas utility segment was $3.5 million for the
quarter ended September 30, 2005, compared to a net loss of
$3.3 million for the quarter ended September 30, 2004.
Electric
Utility Segment Operations
|
|
|
|
WPS Resources'
Electric Utility
|
|
Three
Months
Ended September 30,
|
|
Segment
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
298.6
|
|
$
|
239.0
|
|
|
24.9
|
%
|
Fuel
and
purchased power costs
|
|
|
150.0
|
|
|
74.7
|
|
|
100.8
|
%
|
Margin
|
|
$
|
148.6
|
|
$
|
164.3
|
|
|
(9.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
in
kilowatt-hours
|
|
|
4,207.4
|
|
|
3,730.0
|
|
|
12.8
|
%
|
Electric
utility
revenue increased $59.6 million (24.9%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
Electric utility revenue increased largely due to an increase in electric
sales
volumes and an approved electric rate increase for WPSC's Wisconsin retail
customers. Electric sales volumes increased 12.8%, primarily due to
significantly warmer weather in the third quarter of 2005, compared to the
third
quarter of 2004, and new power sales agreements that were
entered
into with
wholesale customers. As a result of the warm weather, WPSC set all-time records
for peak electric demand in the third quarter of 2005. On December 21,
2004, the PSCW approved a retail electric rate increase of $60.7 million
(8.6%), effective January 1, 2005. The rate increase was required primarily
to
recover increased costs related to fuel and purchased power, costs related
to
the construction of the Weston 4 base-load generation facility, and benefit
costs.
The
electric
utility margin decreased $15.7 million (9.6%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
The decrease can be attributed to a $16.6 million (10.9%) decrease in
WPSC's electric margin, which was largely driven by the sale of Kewaunee
on
July 5, 2005 and the related power purchase agreement. Prior to the sale of
Kewaunee, only nuclear fuel expense was reported as a component of fuel and
purchased power costs. Subsequent to the sale, all payments to Dominion Energy
Kewaunee, LLC for power purchased from Kewaunee are reported as components
of
fuel and purchased power costs. These include both variable payments for
energy
delivered and fixed payments. As a result of the sale, WPSC no longer incurs
operating and maintenance expense, depreciation and decommissioning expense,
or
interest expense for Kewaunee. Excluding the $21.0 million fixed payment
made to
Dominion Energy Kewaunee, LLC in the third quarter of 2005, the electric
utility
margin increased $5.3 million, compared to the same quarter in the prior
year.
This increase was driven by the increase in electric sales volumes and the
rate
increase discussed above, but was largely offset by higher per-unit fuel
and
purchased power costs.
The
quantity of
power purchased by WPSC during the quarter ended September 30, 2005,
increased approximately 168% compared to the same quarter in 2004, and fuel
and
purchased power costs were approximately 68% higher on a per-unit basis.
The
increase in the quantity of power purchased was largely due to power purchased
from Dominion Energy Kewaunee, LLC as previously discussed, warm weather
conditions, WPSC's need to conserve coal because of coal supply issues (see
Other
Future
Considerations),
and a planned
outage at WPSC's Weston 3 generation plant that began in the third quarter
of
2005. The increase in the per-unit cost of fuel and purchased power was driven
by the sale of Kewaunee (primarily related to $21.0 million of fixed payments
being recorded as a component of fuel and purchased power costs), congestion
charges and line loss charges that were not fully offset by credits from
MISO,
increased coal costs related to procurement of coal from alternate sources,
and
the need to supply more energy from higher cost peaking units due to warm
weather conditions, coal conservation efforts, and a planned outage at WPSC's
Weston 3 generation plant that began in the third quarter of 2005. The PSCW
approved the deferral of increased fuel and purchased power costs related
to the
MISO and coal supply matters discussed above and WPSC deferred $15.9 million
of
costs related to these issues in the third quarter of 2005. Excluding deferred
costs, fuel and purchased power costs at WPSC increased $68.7 million. As
discussed above, approximately $21.0 million of the increase in purchased
power
costs related to the Kewaunee fixed payments. Excluding these fixed payments,
fuel and purchased power costs at WPSC increased $47.7 million and total
fuel
and purchased power costs incurred during the quarter exceeded the amount
recovered from ratepayers (as approved in the 2005 rate case), therefore,
having
a negative impact on margin.
The
PSCW allows
WPSC to adjust prospectively the amount billed to Wisconsin retail customers
for
fuel and purchased power if costs are above or below approved levels by more
than 2% on an annualized basis. At June 30, 2005, WPSC was experiencing
fuel and purchased power costs that were more than 2% lower than the approved
level. However, primarily because of the high cost of natural gas resulting
from
the impact hurricanes had on natural gas supply in combination with the need
to
run the natural gas fired peaker units more in the third quarter, at
September 30, 2005, WPSC projects that actual fuel and purchased power
costs for 2005 could be significantly higher than what was allowed in the
2005
rate case.
Electric
utility
earnings decreased $4.1 million (12.8%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004,
largely driven by the higher fuel and purchased power costs discussed above.
Earnings were also negatively impacted because certain costs incurred in
the
third quarter of 2005 related to plant outages, carrying costs on capital
additions, and other costs (which are recovered in rates relatively evenly
throughout the year) were partially recovered in revenue during the first
six
months of the year, leading to higher earnings in those periods.
Gas
Utility
Segment Operations
|
|
|
|
WPS Resources'
|
|
Three
Months
Ended September 30,
|
|
Gas
Utility
Segment Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
71.8
|
|
$
|
45.6
|
|
|
57.5
|
%
|
Purchased
natural gas costs
|
|
|
52.6
|
|
|
28.8
|
|
|
82.6
|
%
|
Margin
|
|
$
|
19.2
|
|
$
|
16.8
|
|
|
14.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
in
therms
|
|
|
128.6
|
|
|
104.1
|
|
|
23.5
|
%
|
Gas
utility revenue
increased $26.2 million (57.5%) for the quarter ended September 30,
2005, compared to the quarter ended September 30, 2004. Gas utility
revenue increased primarily as a result of an increase in the per-unit cost
of
natural gas, higher natural gas throughput volumes, and a rate increase.
Natural
gas costs increased 15.6% (on a per-unit basis) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
Following regulatory practice, WPSC passes changes in the total cost of natural
gas on to customers through a purchased gas adjustment clause, as allowed
by the
PSCW and the MPSC. Natural gas throughput volumes increased 23.5%, primarily
related to an increase in interdepartmental sales from the natural gas utility
to the electric utility as a result of increased electric generation from
natural gas fired combustion turbines. The PSCW issued a final order authorizing
a natural gas rate increase of $5.6 million (1.1%), effective January
1, 2005. The rate increase was primarily driven by higher benefit costs and
the cost of distribution system improvements.
The
natural gas
utility margin increased $2.4 million (14.3%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30,
2004. The higher natural gas utility margin was largely due to the rate increase
mentioned above. The increase in interdepartmental sales volumes to WPSC's
electric utility also had a positive impact on the natural gas
margin.
The
gas utility
realized a net loss of $3.5 million for the quarter ended
September 30, 2005, compared to a net loss of $3.3 million for the
quarter ended September 30, 2004. The higher net loss was attributed to an
increase in operating and maintenance expenses and depreciation expense incurred
by the gas utility.
Overview
of
Nonregulated Operations
Nonregulated
operations consist of natural gas, electric, and other sales at ESI, a
diversified energy supply, services, and natural gas storage company, and
the
operations of PDI, an electric generation company. ESI and PDI are both
reportable segments.
Income
available
for common shareholders attributable to ESI was $8.9 million for the
quarter ended September 30, 2005, compared to $2.5 million for the
same quarter in 2004. The $6.4 million increase in earnings at ESI was
primarily the result of higher natural gas margins.
Income
available
for common shareholders attributable to PDI was $13.2 million for the quarter
ended September 30, 2005, compared to $4.2 million for the quarter ended
September 30, 2004. PDI benefited from realized gains and mark-to-market
gains on derivative instruments utilized to protect the value of a portion
of
PDI's Section 29 federal tax credits and improved margin from Sunbury, partially
offset by a decrease in Section 29 federal tax credits recognized during
the
quarter.
ESI's
Segment
Operations
Total
segment
revenues at ESI were $1,340.9 million for the quarter ended
September 30, 2005, compared to $779.5 million for the same quarter in
2004. The total margin at ESI was $32.3 million for the quarter ended
September 30, 2005, compared to $16.9 million for the quarter ended
September 30, 2004. ESI's nonregulated natural gas and electric operations
are the primary contributors to revenues and margins and are discussed
below.
|
|
|
|
ESI's
Natural
Gas Results
|
|
Three
Months
Ended September 30,
|
|
(Millions,
except sales volumes)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
natural gas revenue
|
|
$
|
1,153.4
|
|
$
|
645.2
|
|
|
78.8
|
%
|
Nonregulated
natural gas cost of sales
|
|
|
1,133.1
|
|
|
647.0
|
|
|
75.1
|
%
|
Margin
|
|
$
|
20.3
|
|
$
|
(1.8
|
)
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales in billion cubic feet (1)
|
|
|
78.4
|
|
|
47.3
|
|
|
65.8
|
%
|
Retail
sales
in billion cubic feet (1)
|
|
|
59.2
|
|
|
77.7
|
|
|
(23.8
|
%)
|
(1)
Represents
gross
physical volumes.
ESI's
natural gas
revenue increased $508.2 million (78.8%), driven by higher natural gas
prices, continued expansion of ESI's Canadian natural gas business, and higher
volumes related to an increase in structured wholesale natural gas
transactions.
The
natural gas
margin at ESI increased $22.1 million for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
The margin related to retail natural gas operations increased
$12.1 million, largely due to improved management of supply for Ohio
residential and commercial customers (including mark-to-market gains on options
utilized to manage supply costs which expire between November 2005 and
September 2006). The margin related to wholesale natural gas operations
increased $10.0 million, primarily driven by the natural gas storage cycle.
The natural gas storage cycle contributed $10.4 million of the increase in
ESI's natural gas margin (for the quarter ended September 30, 2005, the
natural gas storage cycle had a $0.6 million favorable impact on margin,
compared with a $9.8 million negative impact on margin for the same period
in 2004). At September 30, 2005, there was a $5.1 million difference
between the market value of natural gas in storage and the market value of
future sales contracts (net unrealized loss), related to the 2005/2006 natural
gas storage cycle. This difference between the market value of natural gas
in
storage and the market value of future sales contracts related to the 2005/2006
storage cycle is expected to vary with market conditions, but will reverse
entirely and have a positive impact on earnings when all of the natural gas
is
withdrawn from storage.
|
|
|
|
ESI's
Electric Results
|
|
Three
Months
Ended September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
electric revenue
|
|
$
|
186.9
|
|
$
|
133.9
|
|
|
39.6
|
%
|
Nonregulated
electric cost of sales
|
|
|
175.5
|
|
|
115.6
|
|
|
51.8
|
%
|
Margin
|
|
$
|
11.4
|
|
$
|
18.3
|
|
|
(37.7
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes in kilowatt-hours (1)
|
|
|
334.2
|
|
|
579.2
|
|
|
(42.3
|
%)
|
Retail
sales
volumes in kilowatt-hours (1)
|
|
|
1,746.5
|
|
|
2,027.2
|
|
|
(13.8
|
%)
|
(1)
Represents
gross
physical volumes.
ESI's
electric
revenue increased $53.0 million (39.6%). Higher energy market prices were
partially offset by lower volumes from retail electric operations in Michigan
in
the third quarter of 2005.
ESI's
electric
margin decreased $6.9 million (37.7%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
The margin attributed to wholesale electric operations decreased
$6.7 million, driven primarily by a decrease in the margin contributed by
portfolio optimization strategies. Period-by-period variability in the margin
contributed by these activities is expected due to constantly changing market
conditions and timing of gain and loss recognition on certain transactions
pursuant to generally accepted accounting principles. The retail electric
margin
decreased $0.2 million for the quarter ended September 30, 2005,
compared to the quarter ended September 30, 2004, primarily related to a
$4.4 million
decrease in margin from retail electric operations in Michigan, partially
offset
by a $3.4 million increase in margin from operations in Maine and Ohio.
Higher
transmission-related charges resulting from the Seams Elimination Charge
Adjustment, which was implemented on December 1, 2004, as ordered by the
FERC as part of the implementation of MISO, have negatively impacted the
margin
from retail electric operations in Michigan. In addition, tariff changes
granted
to the regulated utilities in Michigan in 2004, coupled with high wholesale
energy prices, have significantly lowered the savings customers can obtain
from
contracting with non-utility suppliers. The tariff changes enable Michigan
utilities to charge a fee to electric customers choosing non-utility suppliers
in order to recover certain stranded costs. ESI has experienced some customer
attrition as a result of the tariff changes and higher wholesale prices,
which
has negatively impacted its margin. In the third quarter of 2005, ESI realized
a
$2.8 million gain from the sale of power that was intended to supply customers
that chose to return to utility suppliers, representing 30-40% of ESI's current
Michigan load. The increase in margin in Ohio was due to improved supply
pricing
compared to the fixed sales price, while the favorable margin increase in
Maine
was due to additional load and better supply management.
PDI's
Segment
Operations
|
|
|
|
PDI's
Operating Results
|
|
Three
Months
Ended September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
other revenues
|
|
$
|
77.8
|
|
$
|
38.9
|
|
|
100.0
|
%
|
Nonregulated
other cost of sales
|
|
|
46.2
|
|
|
26.9
|
|
|
71.7
|
%
|
Margins
|
|
$
|
31.6
|
|
$
|
12.0
|
|
|
163.3
|
%
|
PDI's
revenue
increased $38.9 million (100.0%) for the quarter ended September 30,
2005, compared to the quarter ended September 30, 2004. A
$17.8 million increase in revenue at Sunbury was primarily related to more
opportunities to sell power into the market (made possible by the expiration
of
a fixed price outtake contract on December 31, 2004, and higher energy
market prices). Sunbury's sales volumes increased approximately 14% and the
price received from energy sold into the market in the third quarter of 2005
more than doubled over the price realized from sales under the fixed price
outtake contract in place in 2004. A $9.0 million mark-to-market gain (net
of related premium amortization), and a
$1.9
million
realized gain on derivative instruments utilized to protect the value of
a
portion of PDI's Section 29 federal tax credits also contributed to the higher
revenue. Revenue at PDI's Combined Locks Energy Center increased $6.2 million,
largely due to increasing energy prices and new opportunities to sell power
into
the MISO market in 2005.
PDI's
margin for
the quarter ended September 30, 2005, increased $19.6 million
(163.3%), compared to the quarter ended September 30, 2004. Mark-to-market
and realized gains on derivative instruments utilized to protect the value
of a
portion of PDI's Section 29 federal tax credits (as discussed above) drove
$10.9
million of the margin increase. Sunbury's margin improved $8.7 million
(193.5%), primarily due to more opportunities to sell power into the market
(discussed above). The favorable energy prices made it economical for Sunbury
to
operate all available solid fuel units during the third quarter of 2005.
PDI,
through a
subsidiary, is part owner of a synthetic fuel producing facility that generates
Section 29 federal tax credits. The Section 29 federal tax credits are subject
to phase out if domestic crude oil prices reach specified levels. To manage
exposure to the risk that an increase in oil prices could reduce the
recognizable amount of 2005, 2006, and 2007 Section 29 tax credits, PDI entered
into a series of derivative contracts covering a specified number of barrels
of
oil. These derivatives were entered into in 2005 and mitigate approximately
100%, 95%, and 40% of the Section 29 federal tax credit exposure related
to
rising oil prices in 2005, 2006, and 2007, respectively. The derivative
contracts involve purchased and written call options that provide for net
cash
settlement at expiration based on the average New York Mercantile Exchange
(NYMEX) trading price of oil in relation to the strike price of each option.
The
derivative contracts have not been designated as hedging instruments and,
as a
result, changes in the fair value of the options are recorded currently in
earnings. The timing of recognizing changes in the fair value of these options
likely will not correspond with the timing of when Section 29 federal tax
credits are, or would have been, recognized. As of September 30, 2005,
average annual oil prices for 2005 were below the level where tax credit
phase
out is anticipated to occur.
Overview
of
Holding Company and Other Segment Operations
Holding
Company and
Other operations include the operations of WPS Resources and
WPS Resources Capital as holding companies and the nonutility activities of
WPSC and UPPCO. Holding Company and Other operations had earnings of
$1.6 million during the quarter ended September 30, 2005, compared to
a net loss of $0.7 million during the same period in 2004. A
$2.6 million increase in equity earnings from ATC drove the increase in
earnings. Pre-tax equity earnings from ATC were $6.6 million for the
quarter ended September 30, 2005, compared to $4.0 million for the
quarter ended September 30, 2004.
Operating
Expenses
|
|
|
|
|
|
Three
Months
Ended September 30,
|
|
WPS Resources'
Operating Expenses (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
124.0
|
|
$
|
123.9
|
|
|
-
|
%
|
Depreciation
and decommissioning expense
|
|
|
23.8
|
|
|
26.1
|
|
|
(8.8
|
%)
|
Taxes
other
than income
|
|
|
11.8
|
|
|
11.5
|
|
|
2.6
|
%
|
Operating
and
Maintenance Expense
Overall,
operating
and maintenance expenses did not change significantly for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
WPSC's operating and maintenance expenses decreased $6.7 million, driven by
a $10.0 million decrease related to Kewaunee. WPSC sold its 59% interest
in
Kewaunee to Dominion Energy Kewaunee, LLC on July 5, 2005, and currently
purchases 59% of the output from this facility through a power purchase
agreement. The decrease in operating and maintenance expenses as a result
of the
Kewaunee sale, were partially offset by increases in transmission costs and
pension and postretirement expense. Operating expenses at ESI increased
$5.7 million, primarily due to higher payroll, benefits, and other costs
related to continued business expansion. PDI's operating and maintenance
expenses increased $2.8 million, primarily related to costs incurred to
repair damaged compressor blades at PDI's Syracuse generation facility in
New York. Operating and maintenance expenses related to Holding Company and
Other Segment operations decreased $1.2 million, driven by a decrease in
legal
and consulting expenses.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $2.3 million (8.8%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004,
driven by a $3.1 million decrease in depreciation expense resulting from
the
sale of Kewaunee in July 2005 and lower gains on decommissioning trust assets,
partially offset by additional depreciation due to continued capital investment.
Realized gains on decommissioning trust assets are partially offset by
decommissioning expense pursuant to regulatory practice.
Other
Income (Expense)
|
|
|
|
|
|
Three
Months
Ended September 30,
|
|
WPS Resources'
Other Income (Expense) (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
$
|
9.6
|
|
$
|
9.9
|
|
|
(3.0
|
%)
|
Interest
expense
|
|
|
(15.6
|
)
|
|
(14.9
|
)
|
|
4.7
|
%
|
Minority
interest
|
|
|
1.2
|
|
|
1.2
|
|
|
-
|
%
|
Other
income
(expense)
|
|
$
|
(4.8
|
)
|
$
|
(3.8
|
)
|
|
26.3
|
%
|
Miscellaneous
Income
Miscellaneous
income decreased $0.3 million (3.0%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
The decrease in miscellaneous income was driven by a $1.4 million higher
loss
recognized by PDI from its investments in a synthetic fuel producing facility
and a decrease in realized gains on the nonqualified nuclear decommissioning
trust assets due to the liquidation of the decommissioning trust assets in
the
second quarter of 2005 as a result of the Kewaunee sale. The increased loss
related to the synthetic fuel producing facility was driven by more production
being allocated to PDI's subsidiary (ECO Coal Pelletization #12 LLC) in the
third quarter of 2005 compared to the same period in 2004 and an increase
in the
cost of fuel produced from this facility. These decreases were partially
offset
by a $2.6 million increase in equity earnings from ATC.
Interest
Expense
Interest
expense
increased $0.7 million (4.7%) for the quarter ended September 30,
2005, compared to the quarter ended September 30, 2004. The increase in
interest expense was primarily related to an increase in the average amount
of
short-term debt outstanding during the third quarter of 2005, compared to
the
third quarter of 2004. While average short-term debt levels increased, primarily
to fund capital expenditures related to the Weston 4 base-load plant and
the
Wausau, Wisconsin, to Duluth, Minnesota transmission line, short-term debt
was
reduced significantly in the third quarter of 2005 due to proceeds received
from
the sale of Kewaunee.
Provision
for Income Taxes
The
effective tax
rate was 27.2% for the quarter ended September 30, 2005, compared to 20.8%
for the quarter ended September 30, 2004. The increase in the effective tax
rate was driven by higher income before taxes recognized in the third quarter
of
2005, compared to the third quarter of 2004, in combination with a decrease
in
Section 29 federal tax credits recognized.
Generally
accepted
accounting principles require our year-to-date interim effective tax rate
to
reflect our projected annual effective tax rate. As a result, we estimate
the
effective tax rate for the year and, based upon year-to-date pre-tax earnings,
record tax expense for the period to reflect the projected annual effective
tax
rate. Therefore, although Section 29 federal tax credits are produced
approximately ratably throughout the year, the amount of credits reflected
in
the tax provision for the quarter ended September 30, 2005, was based upon
the projected annual effective tax rate and year-to-date pre-tax
earnings.
Our
ownership
interest in the synthetic fuel operation resulted in recognizing the tax
benefit
of Section 29 federal tax credits totaling $5.5 million for the quarter
ended September 30, 2005, and $7.1 million for the quarter ended
September 30, 2004. As noted above, the amount of Section 29 federal
tax credits recognized is based upon the estimated annual effective tax rate
and
is not necessarily reflective of tax credits produced during the period.
For the
year ending December 31, 2005, we expect to recognize the benefit of
Section 29 federal tax credits totaling approximately $25.7 million. For
the year ended December 31, 2004, we recognized the benefit of Section 29
federal tax credits totaling $27.8 million.
Nine
Months
2005 Compared with Nine Months 2004
WPS Resources
Overview
WPS Resources'
results of operations for the nine months ended September 30 are shown in
the following table:
|
|
|
|
|
|
|
|
WPS Resources'
Results
(Millions,
except share amounts)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Consolidated
operating revenues
|
|
$
|
4,571.7
|
|
$
|
3,538.4
|
|
|
29.2
|
%
|
Income
available for common shareholders
|
|
$
|
138.0
|
|
$
|
82.0
|
|
|
68.3
|
%
|
Basic
earnings per share
|
|
$
|
3.63
|
|
$
|
2.20
|
|
|
65.0
|
%
|
Diluted
earnings per share
|
|
$
|
3.60
|
|
$
|
2.19
|
|
|
64.4
|
%
|
The
$1,033.3 million increase in consolidated operating revenues for the nine
months ended September 30, 2005, compared to the same period in 2004, was
largely driven by an $834.8 million (33.1%) increase in revenue at ESI and
a $157.6 million (16.4%) increase in utility revenue. Higher revenue at ESI
was driven by an increase in natural gas prices, continued expansion of the
Canadian natural gas business, and higher volumes related to an increase
in
structured wholesale natural gas transactions. Electric utility revenue
increased $110.2 million (16.4%), primarily due to an approved retail
electric rate increase, and higher electric sales volumes related to warmer
summer weather conditions and new power sales agreements with wholesale
customers. Gas utility revenue increased $47.4 million due primarily to an
increase in the per-unit cost of natural gas, an approved rate increase,
and
higher natural gas throughput volumes. Revenue changes by reportable segment
are
discussed in more detail below.
Income
available
for common shareholders was $138.0 million ($3.63 basic earnings per share)
for the nine months ended September 30, 2005, compared to
$82.0 million ($2.20 basic earnings per share) for the nine months ended
September 30, 2004. Significant factors impacting the change in earnings
and earnings per share are as follows (and are discussed in more detail
below).
· |
PDI
realized
earnings of $28.7 million for the nine months ended
September 30, 2005, compared to a net loss of $5.0 million for
the same period in 2004, which correlates to a $33.7 million increase
in
earnings at PDI. PDI' s margin increased $45.2 million, largely due
to a $25.2 million improvement in Sunbury's margin, and a combination
of
mark-to-market and realized gains on certain derivative instruments
utilized to protect the value of a portion of PDI's Section 29
federal tax
credits. PDI also benefited from an $8.2 million increase in Section
29
federal tax credits recognized during the nine months ended
September 30, 2005, compared to the same period in the prior year.
PDI's operating results were negatively impacted by an $80.6 million
pre-tax impairment loss that was required to write down Sunbury's
assets
to fair market value and the recognition of $9.1 million of interest
expense related to the termination of Sunbury's interest rate swap;
however, these losses were substantially offset by an $86.8 million
pre-tax gain recognized on the sale of Sunbury's allocated emission
allowances.
|
· |
Warmer
temperatures during the cooling season in 2005, compared to 2004,
and a
retail electric rate increase favorably impacted WPSC's electric
margin,
contributing to a $12.2 million increase in electric utility
earnings; however, the increase in electric utility earnings at
WPSC was
partially offset in the third quarter of 2005 by rising natural
gas
prices.
|
· |
ESI's
earnings increased $8.6 million (51.5%), driven by a $30.3 million
increase in natural gas margin, primarily related to natural gas
operations in Ohio. ESI's electric margin decreased $9.2 million,
driven by lower margins from retail electric operations in Michigan.
Partially offsetting the overall margin improvement was a $7.1
million
increase in ESI's operating and maintenance expenses related to
continued
business expansion.
|
· |
A
$6.2
million pre-tax increase in equity earnings (approximately $3.7
million
after taxes) from our investment in the ATC also contributed to
the
increase in income available for common
shareholders.
|
Overview
of
Utility Operations
Income
available
for common shareholders attributable to the electric utility segment was
$72.4 million for the nine months ended September 30, 2005, compared
to $60.2 million for the nine months ended September 30, 2004. Income
available for common shareholders attributable to the gas utility segment
was
$8.6 million for the nine months ended September 30, 2005,
compared to $9.9 million for the nine months ended September 30,
2004.
Electric
Utility Segment Operations
|
|
|
|
WPS Resources'
Electric Utility
|
|
Nine
Months
Ended September 30,
|
|
Segment
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
782.9
|
|
$
|
672.7
|
|
|
16.4
|
%
|
Fuel
and
purchased power costs
|
|
|
309.9
|
|
|
216.9
|
|
|
42.9
|
%
|
Margin
|
|
$
|
473.0
|
|
$
|
455.8
|
|
|
3.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Sales
in
kilowatt-hours
|
|
|
11,691.1
|
|
|
10,792.0
|
|
|
8.3
|
%
|
Electric
utility
revenue increased $110.2 million (16.4%) for the nine months ended
September 30, 2005, compared to the nine months ended September 30,
2004. Electric utility revenue increased largely due to an approved electric
rate increase for WPSC's Wisconsin retail customers and an increase in electric
sales volumes. On December 21, 2004, the PSCW approved a retail electric
rate increase of $60.7 million (8.6%), effective January 1, 2005. Electric
sales volumes increased 8.3%, primarily due to significantly warmer weather
during the second and third quarters of 2005, compared to the same periods
in
2004, and new power sales agreements that were entered into with wholesale
customers. As a result of the warm weather, both WPSC and UPPCO set all-time
records for peak electric demand in the second and third quarters of 2005.
The
electric
utility margin increased $17.2 million (3.8%) for the nine months ended
September 30, 2005, compared to the nine months ended September 30,
2004. WPSC's electric margin increased
$16.7
million
($37.7 million if the $21.0 million fixed payment made for power purchased
from
Dominion Energy Kewaunee, LLC in the third quarter of 2005 was excluded),
which
was primarily driven by the retail electric rate increase and the increase
in
electric sales volumes discussed above.
The
quantity of
power purchased by WPSC during the nine months ended September 30, 2005,
increased 95% compared to the nine months ended September 30, 2004, and
fuel and purchased power costs were approximately 47% higher on a per-unit
basis. The increase in the quantity of power purchased was largely due to
an
unscheduled outage at Kewaunee, which began in February 2005 (with this unit
returning to service just prior to the sale of this facility to Dominion
Energy
Kewaunee, LLC on July 5, 2005), power purchased from Dominion Energy Kewaunee,
LLC as previously discussed, warm weather conditions, and coal conservation
efforts. The increase in the per-unit cost of fuel and purchased power was
driven by the Kewaunee sale (primarily related to the $21.0 million of fixed
payments recorded as a component of fuel and purchased power costs), congestion
charges and line loss charges that were not fully offset by credits from
MISO,
the need to supply more energy from higher cost peaking units due to warm
weather conditions and coal conservation efforts, and the rising price of
natural gas used as fuel for the peaking units. The 2005 unscheduled outage
at
Kewaunee did not have a significant impact on the electric utility margin
as the
PSCW approved deferral of unanticipated fuel and purchased power costs directly
related to the outage. For the nine months ended September 30, 2005,
$46.2 million of fuel and purchased power costs were deferred in
conjunction with the Kewaunee outage. The PSCW also approved the deferral
of
increased fuel and purchased power costs related to the MISO and coal supply
matters,
and WPSC
deferred $16.3 million of costs related to these issues during the nine months
ended September 30, 2005. Excluding deferred costs, fuel and purchased
power costs at WPSC increased $85.9 million for the nine months ended
September 30, 2005, compared to the same period in 2004, primarily related
to the significant increase in natural gas prices after the hurricanes disrupted
natural gas supply. As discussed above, approximately $21.0 million of the
increase in purchased power costs related to the Kewaunee fixed payments.
Excluding these fixed payments, fuel and purchased power costs at WPSC increased
$64.9 million and total fuel and purchased power costs incurred during the
nine
months ended September 30, 2005, exceeded the amount recovered from
ratepayers (as approved in the 2005 rate case) and, therefore, had a negative
impact on margin.
Warmer
temperatures
during the cooling season in 2005, compared to 2004, and a retail electric
rate
increase favorably impacted WPSC's electric margin, contributing to a
$12.2 million increase in electric utility earnings; however, the increase
in electric utility earnings at WPSC was partially offset in the third quarter
of 2005 by the rising natural gas prices discussed above.
Gas
Utility
Segment Operations
|
|
|
|
WPS Resources'
|
|
Nine
Months
Ended September 30,
|
|
Gas
Utility
Segment Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
336.2
|
|
$
|
288.8
|
|
|
16.4
|
%
|
Purchased
natural gas costs
|
|
|
247.1
|
|
|
203.4
|
|
|
21.5
|
%
|
Margin
|
|
$
|
89.1
|
|
$
|
85.4
|
|
|
4.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
in
therms
|
|
|
599.9
|
|
|
571.1
|
|
|
5.0
|
%
|
Gas
utility revenue
increased $47.4 million (16.4%) for the nine months ended
September 30, 2005, compared to the nine months ended
September 30, 2004. Gas utility revenue increased primarily as a
result of an increase in the per-unit cost of natural gas, a natural gas
rate
increase, and higher natural gas throughput volumes. Natural gas costs increased
12.5% (on a per-unit basis) for the nine months ended September 30, 2005,
compared to the same period in 2004. The PSCW issued a final order authorizing
a
natural gas rate increase of $5.6 million (1.1%), effective
January 1, 2005. Natural gas throughput volumes increased 5.0%,
primarily related to an increase in interdepartmental sales from the natural
gas
utility to the electric utility as a result of increased generation from
combustion turbines. The combustion turbines were dispatched more often due
to
the Kewaunee outage, warm weather conditions, and coal conservation efforts.
Higher natural gas throughput volumes from interdepartmental sales to the
electric utility were partially offset by lower natural gas throughput volumes
to residential customers, related primarily to milder weather in the first
half
of 2005, compared to the same period in 2004.
The
natural gas
utility margin increased $3.7 million (4.3%) for the nine months ended
September 30, 2005, compared to the nine months ended
September 30, 2004. The higher natural gas utility margin was largely due
to the rate increase mentioned above. The increase in interdepartmental sales
volumes to WPSC's electric utility also had a positive impact on the natural
gas
margin.
Income
available
for common shareholders attributed to the gas utility decreased
$1.3 million (13.1%). The higher margin was more than offset by an increase
in operating and maintenance expenses at the gas utility.
Overview
of
Nonregulated Operations
Income
available
for common shareholders attributable to ESI was $25.3 million for the nine
months ended September 30, 2005, compared to $16.7 million for the
same period in 2004. The $8.6 million increase in earnings at ESI was
primarily the result of higher natural gas margins.
Income
available
for common shareholders attributable to PDI was $28.7 million for the nine
months ended September 30, 2005, compared to a net loss of
$5.0 million for the same period in 2004. The
earnings
improvement was largely due to margin improvements (discussed below). PDI
also
benefited from an increase in Section 29 federal tax credits recognized for
the
nine months ended September 30, 2005, compared to the same period in 2004.
PDI's operating results were negatively impacted by an $80.6 million
pre-tax impairment loss that was required to write down Sunbury's long-lived
assets to fair market value and the recognition of $9.1 million in interest
expense related to the termination of Sunbury's interest rate swap; however,
these losses were substantially offset by an $86.8 million pre-tax gain
recognized on the sale of Sunbury's allocated emission allowances.
ESI's
Segment
Operations
Total
segment
revenues at ESI were $3,357.1 million for the nine months ended
September 30, 2005, compared to $2,522.3 million for the same period
in 2004. The total margin at ESI was $90.2 million for the nine months
ended September 30, 2005, compared to $68.7 million for the nine
months ended September 30, 2004. ESI's nonregulated natural gas and
electric operations are the primary contributors to revenues and margins
and are
discussed below.
|
|
|
|
ESI's
Natural
Gas Results
|
|
Nine
Months
Ended September 30,
|
|
(Millions,
except sales volumes)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
natural gas revenue
|
|
$
|
2,947.1
|
|
$
|
2,126.5
|
|
|
38.6
|
%
|
Nonregulated
natural gas cost of sales
|
|
|
2,893.1
|
|
|
2,102.8
|
|
|
37.6
|
%
|
Margin
|
|
$
|
54.0
|
|
$
|
23.7
|
|
|
127.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales in billion cubic feet (1)
|
|
|
195.0
|
|
|
174.4
|
|
|
11.8
|
%
|
Retail
sales
in billion cubic feet (1)
|
|
|
202.5
|
|
|
222.1
|
|
|
(8.8
|
%)
|
(1)
Represents
gross
physical volumes.
ESI's
natural gas
revenue increased $820.6 million (38.6%), driven by higher natural gas
prices, continued expansion of ESI's Canadian natural gas business, and higher
volumes related to an increase in structured wholesale natural gas
transactions.
The
natural gas
margin at ESI increased $30.3 million (127.8%) for the nine months ended
September 30, 2005, compared to the same period in 2004. The margin related
to retail natural gas operations increased $19.5 million, largely due to
improved management of supply for Ohio residential and commercial customers
(including mark-to-market gains on options utilized to manage supply costs
which
expire between November 2005 and September 2006), and new customers in
Ohio. The margin related to wholesale natural gas operations increased
$10.8 million, driven primarily by results of the natural gas storage cycle
and a $3.3 million favorable settlement with a counterparty. The natural
gas storage cycle had a $5.0 million positive impact on ESI's natural gas
margin (for the nine months ended September 30, 2005, the natural gas
storage cycle had a $4.4 million negative impact on margin, compared with a
$9.4 million negative impact on margin for the same period in 2004). The
remaining increase was related to higher margin from structured wholesale
natural gas transactions (the profitability and volume of these products
were
higher due to the increased variability in the price of natural gas during
the
nine months ended September 30, 2005, compared to the same period in 2004).
|
|
|
|
ESI's
Electric Results
|
|
Nine
Months
Ended September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
electric revenue
|
|
$
|
408.0
|
|
$
|
394.1
|
|
|
3.5
|
%
|
Nonregulated
electric cost of sales
|
|
|
373.8
|
|
|
350.7
|
|
|
6.6
|
%
|
Margin
|
|
$
|
34.2
|
|
$
|
43.4
|
|
|
(21.2
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes in kilowatt-hours (1)
|
|
|
723.4
|
|
|
2,796.1
|
|
|
(74.1
|
%)
|
Retail
sales
volumes in kilowatt-hours (1)
|
|
|
5,142.2
|
|
|
5,237.9
|
|
|
(1.8
|
%)
|
(1)
Represents
gross
physical volumes.
ESI's
electric
revenue increased $13.9 million (3.5%). Increased revenue from the July
2004 acquisition of Advantage Energy and higher energy market prices were
partially offset by a decrease in wholesale electric sales volumes related
to
ESI's prior participation in the New Jersey Basic Generation Services Program,
which ended on May 31, 2004, and lower sales volumes from retail electric
operations in Michigan during 2005.
ESI's
electric
margin decreased $9.2 million (21.2%) for the nine months ended
September 30, 2005, compared to the same period in 2004. The retail
electric margin decreased $5.5 million for the nine months ended
September 30, 2005, compared to the nine months ended
September 30, 2004, driven by a $12.6 million
decrease in margin from retail electric operations in Michigan. The decrease
in
margin related to retail electric operations in Michigan was partially offset
by
positive operating results from Advantage Energy and an increase in margin
from
operations in Maine and Ohio. Higher
transmission-related charges resulting from the Seams Elimination Charge
Adjustment, which was implemented on December 1, 2004, as ordered by the
FERC as part of the implementation of the MISO, have negatively impacted
the
margin from retail electric operations in Michigan. In addition, tariff changes
granted to the regulated utilities in Michigan in 2004, coupled with high
wholesale energy prices, have significantly lowered the savings customers
can
obtain from contracting with non-utility suppliers. The tariff changes enable
Michigan utilities to charge a fee to electric customers choosing non-utility
suppliers in order to recover certain stranded costs. ESI has experienced
some
customer attrition as a result of the tariff changes and higher wholesale
energy
prices, which has negatively impacted its margin. In the third quarter of
2005,
ESI realized a $2.8 million gain from the sale of power that was intended
to
supply customers that chose to return to utility suppliers, representing
30-40%
of ESI's current Michigan load. The increase in margin in Ohio was due to
improved supply pricing compared to the fixed sales price, while the margin
increase in Maine was due to additional load and better supply management.
The
margin attributed to wholesale electric operations decreased $3.7 million,
driven primarily by a decrease in the margin contributed by portfolio
optimization strategies. Period-by-period variability in the margin contributed
by these activities is expected due to constantly changing market conditions
and
timing of gain and loss recognition on certain transactions pursuant to
generally accepted accounting principles.
PDI's
Segment
Operations
|
|
|
|
PDI's
Operating Results
|
|
Nine
Months
Ended September 30,
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
other revenues
|
|
$
|
167.2
|
|
$
|
98.5
|
|
|
69.7
|
%
|
Nonregulated
other cost of sales
|
|
|
98.9
|
|
|
75.4
|
|
|
31.2
|
%
|
Margins
|
|
$
|
68.3
|
|
$
|
23.1
|
|
|
195.7
|
%
|
PDI's
revenue
increased $68.7 million (69.7%) for the nine months ended
September 30, 2005, compared to the nine months ended September 30,
2004. A $28.4 million (60.8%) increase in revenue at Sunbury was primarily
related to more opportunities to sell power into the market (made possible
by
the expiration of a fixed price outtake contract on December 31, 2004, and
higher energy market prices). Sunbury's sales volumes were flat over the
prior
year; however, the average price received from energy sold into the market
for
the nine months ended September 30, 2005, was $62.55 per megawatt-hour,
compared to an
average
price
received from energy sold into the market of $48.39 per megawatt-hour for
the
nine months ended September 30, 2004, and an average selling price of
$26.96 per megawatt-hour to the counterparty under the fixed price outtake
contract for the nine months ended September 30, 2004. A $12.9 million
mark-to-market gain (net of related premium amortization) and a $1.9 million
realized gain on derivative instruments utilized to protect the value of
a
portion of PDI's Section 29 federal tax credits also contributed to the higher
revenue. Revenue at PDI's Combined Locks Energy Center in Wisconsin increased
$10.2 million, largely due to increasing energy prices and new opportunities
to
sell power into the MISO market in 2005. A combined $11.2 million increase
in revenue was realized at PDI's steam boiler in Oregon and its Stoneman
generating facility in Wisconsin. The increase in revenue from the steam
boiler
in Oregon was driven by higher demand for energy from the steam customer
at this
facility and an increase in the price of energy sold. Revenue at the Stoneman
generating facility increased as a result of a two-year power sales agreement
that was entered into in the second quarter of 2004.
PDI's
margin for
the nine months ended September 30, 2005, increased $45.2 million
(195.7%), compared to the same period in 2004. Sunbury's margin improved
$25.2 million (427.1%), primarily due to more opportunities to sell power
into the market (discussed above). Mark-to-market and realized gains on
derivative instruments utilized to protect the value of a portion of PDI's
Section 29 federal tax credits drove $14.8 million of the margin increase.
Higher contracted selling prices benefited PDI's Niagara facility in New
York
and its Westwood facility in Pennsylvania, resulting in a combined $3.8 million
margin increase at these facilities.
Overview
of
Holding Company and Other Segment Operations
Holding
Company and
Other operations had earnings of $3.0 million during the nine months ended
September 30, 2005, compared to $0.2 million during the nine months
ended September 30, 2004. The increase in earnings was driven by an
increase in equity earnings from ATC and $1.5 million of deferred financing
costs that were written off in the first quarter of 2004. Pre-tax equity
earnings from ATC were $17.7 million for the nine months ended
September 30, 2005, compared to $11.5 million for the nine months
ended September 30, 2004. These increases were partially offset by a $1.4
million decrease in equity earnings from Wisconsin River Power Company
(resulting from fewer land sales for the nine months ended September 30,
2005) and $1.2 million of increased interest costs and deferred financing
fees
related to restructuring Sunbury's debt to a WPS Resources' obligation in
June 2005.
Operating
Expenses
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
WPS Resources'
Operating Expenses (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
399.4
|
|
$
|
394.1
|
|
|
1.3
|
%
|
Depreciation
and decommissioning expense
|
|
|
119.6
|
|
|
78.4
|
|
|
52.6
|
%
|
Gain
on sales
of emission allowances
|
|
|
(86.8
|
)
|
|
-
|
|
|
-
|
|
Impairment
loss
|
|
|
80.6
|
|
|
-
|
|
|
-
|
|
Taxes
other
than income
|
|
|
35.7
|
|
|
34.8
|
|
|
2.6
|
%
|
Operating
and
Maintenance Expense
Operating
and
maintenance expenses increased $5.3 million (1.3%) for the nine months
ended September 30, 2005, compared to the same period in 2004. Utility
operating and maintenance expenses decreased $3.2 million, primarily
related to a $2.5 million decrease at WPSC. The decrease in operating and
maintenance expense at WPSC was driven by a $10.0 million decrease related
to
Kewaunee in the third quarter of 2005, compared to the third quarter of 2004.
WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee, LLC on
July
5, 2005, and currently purchases 59% of the output of this facility from
Dominion Energy Kewaunee, LLC through a power purchase agreement. The decrease
in operating and maintenance expenses as a result of the Kewaunee sale, was
partially offset by increases in transmission costs and pension and
postretirement expense. The unplanned outage at Kewaunee earlier in 2005
did not
significantly impact the period-over-period change in operating and maintenance
expenses
as the
PSCW approved the deferral of incremental operating and maintenance expenses
that were incurred as a direct result of the unplanned outage. Operating
and
maintenance costs of $11.6 million were deferred during the nine months
ended September 30, 2005, related to this outage. Operating expenses at ESI
increased $7.1 million, primarily due to higher payroll, benefits, and
other costs related to continued business expansion. Operating and maintenance
expenses at PDI increased $3.1 million, driven by a $1.9 million increase
in
operating and maintenance expense at PDI's Syracuse generation facility in
New
York related to costs incurred to repair damaged compressor blades, and a
$0.7
million write-down of spare parts inventory at Sunbury in the second quarter
of
2005. Operating expenses related to Holding Company and Other Segment operations
decreased $1.3 million, driven by a decrease in legal and consulting
expenses.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense increased $41.2 million (52.6%) for the nine months
ended September 30, 2005, compared to the same period in 2004, largely due
to an increase of $40.3 million at WPSC. Approximately $38 million of the
increase resulted from increased gains on decommissioning trust assets prior
to
the sale of Kewaunee. The remaining increase related to continued capital
investment, partially offset by a decrease in depreciation that resulted
from
the sale of the Kewaunee assets in July 2005. Realized gains on decommissioning
trust assets were partially offset by decommissioning expense pursuant to
regulatory practice (see the detailed discussion in Miscellaneous
Income
below).
Gain
on Sale of
Emission Allowances
PDI
completed the
sale of Sunbury's allocated emission allowances in May 2005. The sales proceeds
were $109.9 million, resulting in a pre-tax gain of $85.9 million. PDI
also sold a small amount of Sunbury's emission allowances in the first quarter
of 2005, recognizing a pre-tax gain of $0.9 million. For more information
on Sunbury, see Note 4, Assets
Held for
Sale,
to Condensed
Notes to Financial Statements.
Impairment
Loss
The
sale of
Sunbury's allocated emission allowances in May 2005, provided PDI with more
time
to evaluate various options related to Sunbury. These options range from
closing
the plant, retaining the plant and operating it during favorable economic
periods, or a future sale. Because WPS Resources is no longer committed to
the sale of Sunbury as its only option, generally accepted accounting principles
require all long-lived assets that were previously classified as held for
sale
to be reclassified as held and used at the lower of their carrying value
before
they were classified as held for sale adjusted for depreciation that would
have
been recognized had the assets been continuously classified as held and used,
or
fair value at the date the held for sale criteria was no longer met. Upon
reclassification of the Sunbury plant and related assets as held and used
in the
second quarter of 2005, PDI recorded a non-cash, pre-tax impairment charge
of
$80.6 million. The impairment charge reflects the reduction in the fair
value of the Sunbury plant without the related emission allowances. For more
information on Sunbury, see Note 4, Assets
Held for
Sale,
to Condensed
Notes to Financial Statements.
Other
Income (Expense)
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
WPS Resources'
Other Income (Expense) (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
$
|
62.8
|
|
$
|
20.8
|
|
|
201.9
|
%
|
Interest
expense
|
|
|
(56.2
|
)
|
|
(44.2
|
)
|
|
27.1
|
%
|
Minority
interest
|
|
|
3.4
|
|
|
2.3
|
|
|
47.8
|
%
|
Other
income
(expense)
|
|
$
|
10.0
|
|
$
|
(21.1
|
)
|
|
-
|
|
Miscellaneous
Income
Miscellaneous
income increased $42.0 million for the nine months ended September 30,
2005, compared to the same period in 2004. Approximately $38 million of the
increase in miscellaneous income related to realized gains on the nonqualified
nuclear decommissioning trust assets. The nonqualified decommissioning trust
assets were placed in more conservative investments in the second quarter
of
2005 in anticipation of the sale of Kewaunee, which was completed on July
5,
2005. Pursuant to regulatory practice, the increase in miscellaneous income
related to the realized gains was offset by an increase in decommissioning
expense. Overall, the change in the investment strategy for the nonqualified
decommissioning trust assets had no impact on income available for common
shareholders. An increase of $6.2 million in equity earnings from
WPS Resources' investment in ATC and a $1.5 million write-off in the
first quarter of 2004 of previously deferred financing costs associated with
the
redemption of the trust preferred securities also contributed to the increase
in
miscellaneous income. The increases were partially offset by a $2.6 million
higher loss recognized by PDI from its investments in a synthetic fuel producing
facility and a $1.4 million decrease in equity earnings from Wisconsin River
Power Company (resulting from fewer land sales during the nine months ended
September 30, 2005, compared to the same period in 2004). The increased
loss related to the synthetic fuel producing facility was driven by more
production being allocated to PDI's subsidiary (ECO Coal Pelletization #12
LLC)
for the nine months ended September 30, 2005, compared to the same period
in 2004 and an increase in the cost of fuel produced from this
facility.
Interest
Expense
Interest
expense
increased $12.0 million (27.1%) for the nine months ended
September 30, 2005, compared to the nine months ended September 30,
2004. The increase in interest expense was primarily related to terminating
the
interest rate swap pertaining to Sunbury's non-recourse debt obligation in
the
second quarter of 2005. The interest rate swap was previously designated
as a
cash flow hedge and, as a result, the mark-to-market losses were recorded
as a
component of other comprehensive income. WPS Resources is required to
recognize the amount accumulated within other comprehensive income as a
component of interest expense when the hedged transactions (future interest
payments on debt) are no longer probable of occurring. As a result, the
restructuring of the Sunbury non-recourse debt to a WPS Resources'
obligation in June 2005 triggered the recognition of $9.1 million of
interest expense related to the mark-to-market value of the swap at the date
of
restructuring. The remaining increase in interest expense was primarily related
to an increase in the average level of short-term debt outstanding during
the
nine months ended September 30, 2005, compared to the same period in 2004.
Minority
Interest
The
increase in
minority interest occurred because the minority owner of PDI's subsidiary,
ECO
Coal Pelletization #12 LLC, was not allocated any production from the synthetic
fuel facility for the quarter ended March 31, 2004.
Provision
for Income Taxes
The
effective tax
rate was 23.0% for the nine months ended September 30, 2005, compared to
19.9% for the nine months ended September 30, 2004. Although more tax
credits were recognized during the nine months ended September 30, 2005,
compared to the same period in 2004, the effective tax rate increased as
a
result of a 73.2% increase in income before taxes.
Generally
accepted
accounting principles require our year-to-date interim effective tax rate
to
reflect our projected annual effective tax rate. As a result, we estimate
the
effective tax rate for the year and, based upon year-to-date pre-tax earnings,
record tax expense for the period to reflect the projected annual effective
tax
rate. Therefore, although Section 29 federal tax credits are produced
approximately ratably throughout the year, the amount of credits reflected
in
the tax provision for the nine months ended September 30, 2005, and 2004,
was based upon the projected annual effective tax rate and year-to-date pre-tax
earnings.
Our
ownership
interest in the synthetic fuel operation resulted in recognizing the tax
benefit
of Section 29 federal tax credits totaling $24.1 million for the
nine
months ended September 30, 2005, and $15.9 million for the nine months
ended September 30, 2004. As noted above, the amount of Section 29 federal
tax credits recognized is based upon the estimated annual effective tax rate
and
is not necessarily reflective of tax credits produced during the period.
For the
year ending December 31, 2005, we expect to recognize the benefit of
Section 29 federal tax credits totaling approximately $25.7 million. For
the year ended December 31, 2004, we recognized the benefit of Section 29
federal tax credits totaling $27.8
million.
LIQUIDITY
AND CAPITAL RESOURCES - WPS RESOURCES
We
believe that our cash balances, liquid assets, operating cash flows, access
to
equity capital markets, and borrowing capacity made available because of
strong
credit ratings, when taken together, provide adequate resources to fund ongoing
operating requirements and future capital expenditures related to expansion
of
existing businesses and development of new projects. However, our operating
cash
flows and access to capital markets can be impacted by macroeconomic factors
outside of our control. In addition, our borrowing costs can be impacted
by
short- and long-term debt ratings assigned by independent rating agencies.
Currently, we believe our credit ratings are among the best in the energy
industry (see the Financing
Cash
Flows, Credit Ratings
section
below).
Operating
Cash Flows
During
the nine
months ended September 30, 2005, net cash provided by operating activities
was $172.4 million, compared with $259.3 million during the nine months
ended September 30, 2004. The decrease was driven by changes in working
capital, mostly at ESI. Lower wholesale sales volumes at ESI in the fourth
quarter of 2004, compared to the fourth quarter of 2003, resulted in lower
receivable balances to be collected in 2005, compared to 2004. In addition,
more
favorable natural gas storage opportunities in 2005 resulted in higher inventory
levels for ESI at September 30, 2005, compared to September 30, 2004.
Investing
Cash Flows
Net
cash provided
by investing activities was $11.1 million during the nine months ended
September 30, 2005, compared to $209.9 million used for investing
activities during the nine months ended September 30, 2004. The change is
primarily due to proceeds of $112.5 million and $127.1 million received from
the
sale of Kewaunee and the liquidation of the related non-qualified
decommissioning trust, respectively, along with $110.9 million of proceeds
from the sale of Sunbury's emission allowances. These proceeds were partially
offset by an increase in capital expenditures of $94.3 million (mostly related
to WPSC), as well as increased contributions to ATC.
During
the first
nine months of 2005, WPS Resources invested $35.4 million in ATC,
compared to $18.0 million in the first nine months of 2004. This increased
WPS Resources' consolidated ownership interest in ATC to approximately 28%.
WPS Resources contributed $12.6 million of capital to ECO Coal
Pelletization #12 in the first nine months of 2005 compared to
$12.0 million in the first nine months of 2004.
Capital
Expenditures
Capital
expenditures by business segment for the nine months ended September 30 are
as follows:
|
|
|
|
|
|
(Millions)
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Electric
utility
|
|
$
|
264.6
|
|
$
|
144.6
|
|
Gas
utility
|
|
|
25.2
|
|
|
47.6
|
|
ESI
|
|
|
0.1
|
|
|
1.2
|
|
PDI
|
|
|
2.9
|
|
|
3.4
|
|
Other
|
|
|
0.9
|
|
|
2.6
|
|
WPS Resources
consolidated
|
|
$
|
293.7
|
|
$
|
199.4
|
|
The
increase in
capital expenditures at the electric utility for the nine months ended
September 30, 2005, as compared to the same period in 2004, is mainly due
to higher capital expenditures associated with the construction of Weston
4. Gas
utility capital expenditures decreased primarily due to the completion of
the
automated meter-reading project.
Dairyland
Power
Cooperative has confirmed its intent to purchase an interest in Weston 4,
subject to a number of conditions. If the purchase is completed, electric
utility expenditures made by WPSC for Weston 4 will be reduced by 30 percent.
The agreement with Dairyland Power Cooperative is part of our continuing
plan to
provide least-cost, reliable energy for the increasing electric demand of
our
customers and to reduce risk. We expect to close on this transaction by the
end
of 2005.
Financing Cash
Flows
Net
cash used for
financing activities was $196.1 million during
the nine months ended September 30, 2005, compared to $45.0 million
during the nine months ended September 30, 2004. The increase is attributed
to increased repayments of commercial paper in 2005, partially offset by
the
repayment of long-term debt in 2004 using the proceeds from a 2003 issuance
of
common stock at WPS Resources.
Significant
Financing Activities
WPS Resources
had $138.0 million in outstanding
commercial paper borrowings at September 30, 2005, compared to
$130.9 million in outstanding
commercial paper borrowings at September 30, 2004. WPS Resources had
other outstanding short-term debt of $10.0 million and $12.7 million
as of September 30, 2005, and 2004, respectively.
In
2005 and 2004, we issued new shares of common stock under our Stock Investment
Plan and under certain stock-based employee benefit and compensation plans.
As a
result of these plans, equity increased $26.1 million and
$22.3 million in the nine months ended September 30, 2005, and 2004,
respectively. WPS Resources did not repurchase any existing common stock
during the nine months ended September 30, 2005, or 2004.
On
June 17, 2005, $62.9 million of non-recourse debt at a PDI subsidiary
that was used to finance the purchase of Sunbury was converted to a five-year
WPS Resources obligation in connection with the sale of Sunbury's allocated
emission allowances. An additional $2.7 million drawn on a line of credit
at PDI was rolled into the five-year WPS Resources obligation. The floating
interest rate on the total five-year WPS Resources obligation of
$65.6 million has been fixed at 4.595% through two interest rate
swaps.
On
January 19, 2004, WPSC retired $49.9 million of its 7.125% series first
mortgage bonds. These bonds had an original maturity date of July 1,
2023.
On
January 8, 2004, WPS Resources retired $50.0 million of its 7.0% trust
preferred securities. As a result of this transaction, WPSR Capital Trust
I, a
Delaware business trust, was dissolved.
Credit
Ratings
WPS Resources
and WPSC use internally generated funds and commercial paper borrowings to
satisfy most of their capital requirements. WPS Resources also periodically
issues long-term debt and common stock to reduce short-term debt, maintain
desired capitalization ratios, and fund future growth. WPS Resources may
seek nonrecourse financing for funding nonregulated acquisitions.
WPS Resources' commercial paper borrowing program provides for working
capital requirements of the nonregulated businesses and UPPCO. WPSC has its
own
commercial paper borrowing program. WPSC also periodically issues long-term
debt, receives equity contributions from WPS Resources, and makes payments
for return of capital to WPS Resources to reduce short-term debt, fund
future growth, and maintain capitalization ratios as authorized by the PSCW.
The
specific forms of long-term financing, amounts, and timing depend on the
availability of projects, market conditions, and other factors.
The
current credit
ratings for WPS Resources and WPSC are listed in the table
below.
|
|
|
Credit
Ratings
|
Standard
& Poor's
|
Moody's
|
WPS Resources
Senior unsecured debt
Commercial paper
Credit facility
|
A
A-1
-
|
A1
P-1
A1
|
WPSC
Senior secured debt
Preferred stock
Commercial paper
Credit facility
|
A+
A-
A-1
-
|
Aa2
A2
P-1
Aa3
|
In
January 2005, Standard & Poor's downgraded its ratings for WPSC one level to
the rating identified above and established a negative outlook. At the same
time, Standard & Poor's affirmed WPS Resources' ratings but changed the
outlook from stable to negative. In taking these actions, Standard & Poor's
cited WPSC's substantial capital spending program and the risk profile of
WPS Resources' nonregulated businesses.
In
September 2005, Standard & Poor’s placed all of WPS Resources’ and
WPSC’s credit ratings on CreditWatch with negative implications as a result of
WPS Resources’ announcement that it entered into a definitive agreement
with Aquila, Inc. to acquire Aquila's natural gas distribution operations
in
Michigan and Minnesota. Although Standard & Poor’s noted that
WPS Resources’ business risk profile could be strengthened with the
inclusion of the additional natural gas distribution utilities, they will
not
remove the CreditWatch with negative implications until meeting with the
company
to assess the assets to be acquired, better understand the integration strategy,
and review a new financial forecast that incorporates the two proposed natural
gas acquisitions.
Similarly,
in
September 2005, Moody’s announced no change to the current ratings, but
changed the rating outlook for WPS Resources and WPSC from stable to
negative, citing a potential risk that the company’s leverage may increase over
the next several years.
Still,
we believe
these ratings continue to be among the best in the energy industry and allow
us
to access commercial paper and long-term debt markets on favorable terms.
Credit
ratings are not recommendations to buy, are subject to change, and each rating
should be evaluated independently of any other rating.
Rating
agencies use
a number of both quantitative and qualitative measures in determining a
company's credit rating. These measures include, but are not limited to,
business risk, liquidity risk, competitive
position,
capital
mix, financial condition, predictability of cash flows, management strength,
and
future direction. Some of the quantitative measures can be analyzed through
a
few key financial ratios, while the qualitative measures are more
subjective.
WPS Resources
and WPSC hold credit lines to back 100% of their commercial paper borrowing
and
letters of credit. These credit facilities are based on a credit rating of
A-1/P-1 for WPS Resources' commercial paper and A-1/P-1 for WPSC's
commercial paper. A significant decrease in the commercial paper credit ratings
could adversely affect the companies by increasing the interest rates at
which
they can borrow and potentially limiting their access to funds through the
commercial paper market. A restriction in the companies' ability to use
commercial paper borrowing to meet working capital needs would require them
to
secure funds through alternate sources resulting in higher interest expense,
higher credit line fees, and a potential delay in the availability of
funds.
ESI
maintains
underlying agreements to support its electric and natural gas operations.
In the
event of a deterioration of WPS Resources' credit rating, many of these
agreements allow the counterparty to demand additional assurance of payment.
This provision could pertain to existing business, new business, or both
with
the counterparty. The additional assurance requirements could be met with
letters of credit, surety bonds, or cash deposits and would likely result
in
WPS Resources being required to maintain increased bank lines of credit or
incur additional expenses, and could restrict the amount of business ESI
can
conduct.
ESI
uses the NYMEX
and over-the-counter financial markets to hedge its exposure to physical
customer obligations. These hedges are closely correlated to the customer
contracts, but price movements on the hedge contracts may require financial
backing. Certain movements in price for contracts through the NYMEX exchange
require posting of cash deposits equal to the market move. For the
over-the-counter market, the underlying contract may allow the counterparty
to
require additional collateral to cover the net financial differential between
the original contract price and the current forward market. Increased
requirements related to market price changes usually result in a temporary
liquidity need that will unwind as the sales contracts are fulfilled.
Future
Capital Requirements and Resources
Contractual
Obligations
The
following table
summarizes the contractual obligations of WPS Resources, including its
subsidiaries.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
Due
By Period
|
|
Contractual
Obligations
As
of
September 30, 2005
(Millions)
|
|
Total
Amounts
Committed
|
|
Less
Than
1
Year
|
|
1
to
3
Years
|
|
3
to
5
Years
|
|
Over
5
Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt principal and interest payments
|
|
$
|
1,276.2
|
|
$
|
28.1
|
|
$
|
111.0
|
|
$
|
262.0
|
|
$
|
875.1
|
|
Operating
leases
|
|
|
23.9
|
|
|
1.4
|
|
|
7.5
|
|
|
5.8
|
|
|
9.2
|
|
Commodity
purchase obligations
|
|
|
6,188.3
|
|
|
1,601.8
|
|
|
3,091.7
|
|
|
577.7
|
|
|
917.1
|
|
Purchase
orders
|
|
|
485.7
|
|
|
270.4
|
|
|
184.4
|
|
|
30.9
|
|
|
-
|
|
Capital
contributions to equity method investment
|
|
|
168.7
|
|
|
27.6
|
|
|
134.1
|
|
|
7.0
|
|
|
-
|
|
Other
|
|
|
419.0
|
|
|
30.6
|
|
|
89.6
|
|
|
49.7
|
|
|
249.1
|
|
Total
contractual cash obligations
|
|
$
|
8,561.8
|
|
$
|
1,959.9
|
|
$
|
3,618.3
|
|
$
|
933.1
|
|
$
|
2,050.5
|
|
Long-term
debt
principal and interest payments represent bonds issued, notes issued, and
loans
made to WPS Resources and its subsidiaries. We record all principal
obligations on the balance sheet. Commodity purchase obligations represent
mainly commodity purchase contracts of WPS Resources and its subsidiaries.
Energy supply contracts at ESI included as part of commodity purchase
obligations are generally entered into to meet obligations to deliver energy
to
customers. WPSC and UPPCO expect to
recover
the costs
of their contracts in future customer rates. Purchase orders include obligations
related to normal business operations and large construction obligations,
including 100% of Weston 4 obligations; however, we expect 30% of these costs
to
be paid by Dairyland Power Cooperative after the close of Dairyland’s purchase
of 30% of Weston 4, which is expected to close late in the year. Included
in the
purchase orders listed in the table above, is $301.2 million related to Weston
4
purchase obligations. Capital contributions to equity method investment include
our commitment to fund a portion of the Wausau, Wisconsin, to Duluth, Minnesota,
transmission line. The table above does not reflect obligations under the
definitive agreement with Aquila, Inc. to acquire Aquila’s natural gas
distribution operations in Michigan and Minnesota. Other mainly represents
expected pension and postretirement funding obligations.
Capital
Requirements
WPSC
makes large
investments in capital assets. Net construction expenditures are expected
to be
approximately $1.0 billion in the aggregate for the 2005 through 2007 period.
The largest of these expenditures is for the construction of Weston 4, for
which
WPSC is expected to incur costs of $419 million between 2005 through 2007,
assuming 70% ownership after the expected purchase of a 30% interest in Weston
4
by Dairyland Power Cooperative.
As
part of its regulated utility operations, on September 26, 2003, WPSC
submitted an application for a Certificate of Public Convenience and Necessity
to the PSCW seeking approval to construct Weston 4, a 500-megawatt coal-fired
generation facility near Wausau, Wisconsin. The facility is estimated to
cost
approximately $779 million (including the acquisition of coal trains), of
which WPSC will be responsible for 70% assuming Dairyland Power Cooperative
purchases their expected 30% interest in Weston 4. Through September 30,
2005, WPSC has incurred a total cost of $295 million related to this
project. In addition, WPSC expects to incur additional construction costs
through the date the plant goes into service of about $75 million to fund
construction of the transmission facilities required to support Weston 4.
ATC
will reimburse WPSC for the construction costs of the transmission facilities
and related carrying costs when Weston 4 becomes commercially operational,
which
is expected to occur in June 2008.
On
October 7, 2004, we received the final PSCW order granting authority to proceed
with construction of Weston 4, contingent upon receipt of an air permit.
The air
permit was issued by the WDNR on October 19, 2004. We believe the air
permit is one of the most stringent in the nation, which means that
Weston 4 will be one of the cleanest plants of its kind in the
United States. Construction began in October 2004. On November 15, 2004, a
petition was filed with the WDNR contesting the air permit issued. On
December 2, 2004, the WDNR granted the petition and forwarded the matter to
the Division of Hearings and Appeals. Construction continues, and a contested
case hearing on the air permit was held in September 2005. A decision from
the Administrative Law Judge is expected in January 2006.
Other
significant
anticipated expenditures during this three-year period (2005 through 2007)
include:
· |
mercury
and
pollution control projects -
$84 million
|
· |
corporate
services infrastructures - $34
million
|
On
April 18, 2003, the PSCW approved WPSC's request to transfer its interest
in the
Wausau, Wisconsin, to Duluth, Minnesota, transmission line to the ATC.
WPS Resources committed to fund 50% of total project costs incurred up to
$198 million, and receive additional equity in the ATC in exchange for the
project funding. WPS Resources may terminate funding if the project extends
beyond January 1, 2010. On December 19, 2003, WPSC and ATC received
approval to continue the project at a revised cost estimate of
$420.3 million to reflect additional costs for the project resulting from
time delays, added regulatory requirements, changes and additions to the
project, and ATC overhead costs. The final portion of the line is expected
to be
placed in service in 2008. WPS Resources has the right, but not the
obligation, to provide additional funding in excess of $198 million up to
50% of the revised cost estimate. Allete, Inc. has an option to fund a portion
of this commitment and intends to fund $60 million by the end of 2006. This
would ultimately decrease the amount of additional equity WPS Resources has
in
the ATC. For the period 2005 through 2009, WPS Resources expects to fund
up to
approximately $176 million for
its
portion of the
Wausau to Duluth transmission line assuming Allete, Inc. does not exercise
its
option, and approximately $116 million if Allete does exercise its option.
The
$176 million of capital contributions includes approximately
$35 million of contributions made to the ATC in the first nine months of
2005.
WPS Resources
expects to provide additional capital contributions to ATC of approximately
$53
million for the period 2005 through 2007 for other projects, assuming Allete
does not exercise its option. If Allete does exercise its option, this amount
will be reduced to $46 million.
UPPCO
is expected
to incur construction expenditures of about $49 million in the aggregate
for the period 2005 through 2007, primarily for electric distribution
improvements and repairs and safety measures at hydroelectric
facilities.
Capital
expenditures identified at PDI for 2005 through 2007 are expected to be
approximately $3 million.
Capital
expenditures identified at ESI for 2005 through 2007 are expected to be
approximately $8 million, largely due to expenditures related to Advantage
Energy, computer equipment related to business expansion and normal technology
upgrades.
All
projected
capital and investment expenditures are subject to periodic review and revision
and may vary significantly from the estimates depending on a number of factors,
including, but not limited to, industry restructuring, regulatory constraints,
acquisition opportunities, market volatility, and economic trends. Other
capital
expenditures for WPS Resources and its subsidiaries for 2005 through 2007
could be significant depending on its success in pursuing development and
acquisition opportunities. When appropriate, WPS Resources may seek
nonrecourse financing for a portion of the cost of these
acquisitions.
Capital
Resources
As
of September 30, 2005, both WPS Resources and WPSC were in compliance
with all of the covenants under their lines of credit and other debt
obligations.
For
the period 2005
through 2007, WPS Resources plans to use internally generated funds net of
forecasted dividend payments, cash proceeds from asset sales, and debt and
equity financings to fund capital requirements. WPS Resources plans to
maintain current debt to equity ratios at appropriate levels to support current
credit ratings and corporate growth. Management believes WPS Resources has
adequate financial flexibility and resources to meet its future
needs.
WPS Resources
has the ability to issue up to $450.0 million of debt and equity under its
currently effective shelf registration statement. WPSC has the ability to
issue
up to an additional $375.0 million of debt under its currently effective
shelf registration statements.
On
June 2, 2005, WPS Resources entered into an unsecured
$500 million 5-year credit agreement. This revolving credit line replaces
the former 364-day credit line facilities, which had a borrowing capacity
of
$400 million. WPSC also entered into a new 5-year credit facility, for
$115 million, to replace its former 364-day credit line facility for the
same amount. The credit lines are used to back 100% of WPS Resources' and
WPSC's commercial paper borrowing programs and the majority of letters of
credit
for WPS Resources and WPSC. As of September 30, 2005, there was a
total of $404.5 million and $79.2 million available under
WPS Resources' and WPSC's credit lines, respectively.
In
May 2005, PDI entered into transactions with multiple counterparties to sell
the
allocated emission allowances associated with Sunbury. In July 2005, WPSC
sold
its portion of Kewaunee. A portion of the proceeds from the Kewaunee sale
was
used to retire short-term debt at WPSC. The remainder of the proceeds from
the
sale of both the Sunbury emissions allowances and Kewaunee will be used by
WPS Resources for investing activities and general corporate purposes of
its subsidiaries, including reducing the amount of outstanding debt. For
more
information regarding these sales, see the discussion below under Other
Future
Considerations.
WPS Resources
intends to sign bridge credit agreements of $557.5 million and $300 million
in early November 2005. The bridge facilities are intended to backup commercial
paper borrowing related to the purchase of the Michigan and Minnesota natural
gas distribution operations from Aquila and to support purchase price
adjustments related to working capital at the time of the closing of the
transactions. The capacity under the bridge facilities will be reduced by
the
amount of proceeds from any long-term financing we complete prior to closing,
with the exception of proceeds from a common stock sale scheduled to occur
prior
to signing the purchase agreements. The credit agreements will be further
reduced as permanent or replacement financing is secured at the time of closing
the transactions, and will expire by September 2007. The bridge credit
agreements have representations and covenants that are similar to those in
our
existing credit facilities.
WPS Resources
plans to permanently finance the acquisition of the Michigan and Minnesota
natural gas distribution operations from Aquila with a combination of debt
and
equity.
Other
Future Considerations
Agreement
to
Purchase Aquila's Michigan and Minnesota Natural Gas Distribution
Operations
On
September 21, 2005, WPS Resources, through wholly owned subsidiaries,
entered into two definitive agreements with Aquila Inc. to acquire Aquila's
natural gas distribution operations in Michigan and Minnesota for approximately
$558 million, exclusive of direct costs of the acquisition. The purchase
price
also excludes certain adjustments related to working capital, including accounts
receivable, unbilled revenue, inventory, and certain other current assets.
The
purchase price is also subject to certain other closing and post-closing
adjustments, primarily net plant adjustments.
The
Minnesota
natural gas assets provide natural gas distribution service to about 200,000
customers throughout the state in 165 cities and communities including Grand
Rapids, Pine City, Rochester, and Dakota County with 226 employees. Annual
natural gas throughput is approximately 761 million therms per year, which
is
almost as large as WPS Resources' existing regulated natural gas
operations. The assets operate under a cost-of-service environment and are
currently allowed an 11.71% return on equity on a 50% equity component of
the
regulatory capital structure.
The
Michigan
natural gas assets provide natural gas distribution service to about 161,000
customers, mainly in southern Michigan in 147 cities and communities including
Otsego, Grand Haven, and Monroe with 182 employees. Annual natural gas
throughput is approximately 360 million therms per year. Like Minnesota,
the
assets also operate under a cost-of-service environment and are currently
allowed an 11.4% return on equity on a 45% equity component of the regulatory
capital structure.
WPS Resources
plans that permanent financing for the acquisition will be raised through
the
issuance of a combination of equity and long-term debt.
The
transaction is
subject to various state and other regulatory approvals, including approval
from
the Michigan Public Service Commission and the Minnesota Public Utilities
Commission, and is subject to compliance with the Hart-Scott-Rodino Act.
Assuming all approvals are obtained in a timely manner, WPS Resources
anticipates closing the transactions in the first half of 2006.
Excluding
one-time
integration costs, the transaction is expected to be accretive to
WPS Resources' earnings over the first 12 months following the close of the
acquisition. WPS Resources anticipates maintaining its current dividend
policy following the closing.
Sunbury
WPS Resources
made capital contributions of $1.0 million to Sunbury during the first nine
months of 2005. In 2004, WPS Resources made capital contributions of
$24.5 million to Sunbury, all during the first nine months of 2004.
Contributions made in the first nine months of 2005 were necessary to meet
certain working capital requirements. In 2004, WPS Resources' Board of
Directors granted authorization to contribute up to $32.8 million of
capital to Sunbury. At September 30, 2005, $7.3 million of the
originally authorized amount remains available for contribution. Financial
results for Sunbury have improved in 2005, compared to 2004, primarily due
to
more opportunities to sell power into the market as the result of the expiration
of a fixed price outtake contract on December 31, 2004. Current energy
market prices are significantly higher than the fixed price received under
the
expired contract.
The
sale of
Sunbury's allocated emission allowances was completed in May 2005. Total
sales
proceeds of $109.9 million were utilized by Sunbury to eliminate its
nonrecourse debt obligation, which provided PDI with flexibility to consider
various alternatives for the plant. All available solid fuel units at the
Sunbury plant were operated through September 30, 2005, due to favorable
market
conditions. Should market conditions decline, PDI will consider placing the
plant in a stand-by mode of operation, which will serve to minimize future
operating expenses while maintaining several options for the plant (including
closing the plant, retaining the plant and operating it during favorable
economic periods, or a potential future sale of the plant). Dispatching Sunbury
in a stand-by mode of operation will help focus production on higher-priced
periods, generally in the winter and mid-summer months. The success of a
stand-by mode of operation will depend on Sunbury's ability to minimize costs
during non-operating periods. Current projections show Sunbury dispatching
and
achieving positive cash flows for the remainder of the year; therefore, it
appears that the authorized level of capital available to meet the cash flow
needs of Sunbury is sufficient through 2005.
Kewaunee
In
early July 2005, Kewaunee returned to service following an unplanned outage
that
began in February 2005. As approved by the PSCW and FERC, WPSC deferred outage
costs associated with incremental fuel, purchased power, and operating and
maintenance costs.
On
July 5, 2005, WPSC completed the sale of its 59% ownership interest in Kewaunee
to a subsidiary of Dominion Resources, Inc. At the same time, Wisconsin Power
and Light Company sold its 41% ownership interest to Dominion. The major
benefits of the sale for WPSC included shifting financial risk from utility
customers and shareholders to Dominion, greater certainty of future costs,
and
the return of nonqualified decommissioning funds to customers.
WPSC's
share of the
cash proceeds from the sale was $112.5 million. Dominion received the
assets in WPSC's qualified decommissioning trust and assumed responsibility
for
the eventual decommissioning of Kewaunee. These trust assets had a pre-tax
fair
value of $243.6 million at closing. WPSC retained ownership of the assets
contained in its nonqualified decommissioning trust. The sale of Kewaunee
resulted in a loss of $12.1 million, which equals the proceeds from the
sale less the net assets sold, adjusted by several additional items. The
most
significant of these adjustments is the fair value of an indemnity issued
to
cover certain costs Dominion may incur related to the recent unplanned outage.
In addition, the adjustments included certain costs related to the termination
of the plant operating agreement and withdrawal from WPS Resources' investment
in the Nuclear Management Company ("NMC"), which served as the licensed operator
of Kewaunee. WPSC has received approval from the PSCW for deferral of the
loss
resulting from this transaction and related costs. WPSC has proposed that
proceeds of $127.1 million received from the liquidation of the
nonqualified decommissioning trust assets be refunded to customers, net of
the
loss on the sale of the plant assets and costs related to the 2004 and 2005
Kewaunee outages.
Beaver
Falls
PDI's
Beaver Falls
generation facility in New York has been out of service since late
June 2005. An unplanned outage was caused by the failure of the first stage
turbine blades. At this time, inclusive of estimated insurance recoveries,
PDI
estimates that it will cost between $3 and $5 million to repair the turbine
and replace the damaged blades. If the estimated repair costs are subsequently
revised upward or the repair costs are not fully recoverable through insurance,
then a possibility exists that the repairs either will not be made or will
cause
the undiscounted cash flows related to future operations to be insufficient
to
recover the carrying value of the plant, resulting in an impairment. The
carrying value of the Beaver Falls generation facility at September 30,
2005 is $18.6 million.
Asset
Management Strategy
WPS Resources
is finalizing its sales strategy for the balance of its identified real estate
holdings no longer needed for operations.
Regulatory
For
a discussion of
regulatory considerations, see Note 16, Regulatory
Environment.
Industry
Restructuring
-Ohio-
In
May 1999, the Ohio Legislature passed Senate Bill 3, which introduced
market-based rates and instituted competitive retail electric services. The
bill
also established a market development period beginning January 1, 2001, and
extending no later than December 31, 2005, after which rates would be set
at market-based prices. During this market development period, ESI had
contracted to be the supplier for approximately 100,000 residential, small
commercial, and government facilities in the FirstEnergy service areas under
the
State of Ohio provisions for Opt-out Electric Aggregation Programs.
The
Public
Utilities Commission of Ohio requested the Ohio electric distribution utilities
to file rate stabilization plans covering the 2006-2008 time period to avoid
rate shock at the end of the market development period. A plan submitted
by
FirstEnergy establishes electric rates for consumers beginning in 2006 if
a
competitive bid auction ordered by the Public Utilities Commission of Ohio
does
not produce better benefits. The price resulting from an auction conducted
on
December 8, 2004, was inadequate. Because the FirstEnergy plan is priced
lower than current market power prices, ESI will discontinue service to
customers of the existing aggregation programs after the expiration of those
contracts in December 2005. For 2006, the loss of these customers is
estimated to have a $3.8 million negative impact on ESI's gross margin.
On
September 23, 2004, an Ohio House Bill was introduced, proposing change to
the electric restructuring law. The bill proposes to give the Public Utilities
Commission of Ohio explicit authority to implement rate stabilization plans
in
certain circumstances. Recent news releases indicate an increased momentum
in
the Ohio General Assembly for legislation that would make major changes to
Senate Bill 3 in 2005.
The
Ohio Senate
held meetings during March 2005 to hear from all parties involved as they
develop a statewide energy policy (natural gas and electric). The Senate
heard
and considered such issues as rolling back Senate Bill 3, pushing ahead with
electric deregulation, and the need for rate-based utility construction of
new
power plants in the state. In addition to the electric issues, the Senate
also
heard about natural gas issues. ESI participated and testified, urging the
Senate to move forward to implement a competitive environment. If the regulatory
climate and market allow, ESI may bring electric power market opportunities
to
Ohio communities for 2007.
-Michigan-
Under
the current
Electric Choice program in Michigan, ESI, through its Michigan subsidiary,
has
established itself as a significant supplier to the industrial and commercial
markets. However, recent high wholesale energy prices coupled with both approved
and pending tariff changes for the regulated utilities have significantly
lowered the savings customers can obtain from contracting with non-utility
suppliers. As a result, many customers have returned to the bundled tariff
service of the incumbent utility. The high wholesale energy prices and tariff
changes have caused a reduction in new business and renewals for ESI, decreasing
contracted demand levels from a high of approximately 900 megawatts to a
current level of 465 megawatts. The MPSC is expected to provide orders in
two
significant proceedings by the end of the year that will clarify the outlook
for
Electric Choice.
The
status of
Michigan's electric markets has been the subject of hearings in both the
Senate
and House Energy Committees. However, no new legislation has been proposed
to
date. The Senate bills that were introduced in 2004 contained provisions
that
would have substantially harmed the Electric Choice market and returned Michigan
to a model of the regulated supply monopoly. If similar legislation is proposed
and passed, it could diminish the benefits of competitive supply for Michigan
business customers. The impact on ESI could range from maintaining Michigan
business with little or no growth to an inability to re-contract any business,
leading to a possible decision by ESI to exit Michigan's electric market
and
redirect resources to more vibrant markets. It is not unreasonable to expect
changes, either from the legislature or the MPSC, that will have some level
of
negative impact on ESI, but it is unlikely that Michigan customers will lose
all
of the benefits of competition and revert back to a fully regulated monopoly
supply. ESI is actively participating in the legislative and regulatory process
in order to protect its interests in Michigan.
-Midwest
Independent Transmission System Operator-
WPSC,
UPPCO, and
ESI are members of the Midwest Independent Transmission System Operator (MISO),
which introduced its "Day 2" energy markets on April 1, 2005, when it began
centrally dispatching wholesale electricity along with providing transmission
service throughout much of the Midwest. The new market is based on a locational
marginal pricing system, which is similar to that used by the successful
PJM
regional transmission organization. The pricing mechanism expands the existing
market from a physical market to also include financial implications and
is
intended to send price signals to stakeholders where generation or transmission
system expansion is needed. This methodology is consistent with and responsive
to the FERC direction over the past four years to develop a standard competitive
generation market. Based upon the early results of the transition, it does
not
appear that the new market will have a material ongoing impact on the financial
results of WPS Resources. WPS Resources will continue to work closely
with the MISO and the FERC to ensure that any issues are dealt with such
that
the financial impact continues to be minimal. WPSC has been granted approval
by
the PSCW to defer costs and benefits related to the new market for inclusion
in
future rates for its Wisconsin retail electric customers. Costs and benefits
related to WPSC's and UPPCO's Michigan and wholesale electric customers will
also flow through fuel adjustment mechanisms.
Although
the market
is running well so far, there are still market issues that must be resolved.
MISO "Day 2" has the potential to significantly impact the cost of
transmission for eastern Wisconsin and the Upper Peninsula of Michigan system,
including WPSC and UPPCO, as well as our marketing affiliates in the MISO
footprint, such as ESI. Under this market-based approach, where there is
abundant transmission capacity, overall costs should be less due to the ability
to access cheaper generation from across the MISO footprint. For areas with
narrowly constrained transmission capacity, such as Wisconsin and the
Upper Peninsula of Michigan, costs could be higher due to the congestion
and marginal loss pricing components. For the utilities in eastern Wisconsin
and
the Upper Peninsula of Michigan, mechanisms have been deployed to offset
these
potential increased costs in the first five years of the "Day 2" market.
If the
market works appropriately, the costs to ESI, excluding the Seams Elimination
Charge Adjustment (discussed below), should be similar to the pre-"Day 2"
market
costs. If there are incremental costs or savings to WPSC and UPPCO, they
would
be passed through to our customers under existing tariffs.
WPSC
has
established an energy market risk policy and a risk management plan to
facilitate utilization of financial instruments for managing market risks
associated with the "Day 2" energy market. The PSCW has approved this plan,
allowing WPSC to pass the costs and benefits of several specific risk management
strategies through the PSCW's fuel rules, deferral, or escrow processes.
Seams
Elimination Charge Adjustment
Through
a series of
orders issued by FERC, Regional Through and Out Rates for transmission service
between the MISO and the PJM Interconnection were eliminated effective
December 1, 2004. To compensate transmission owners for the revenue they
will no longer receive due to this elimination, the FERC ordered a transitional
pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to
be
put into place. Load-serving entities will pay these SECA charges during
a
16-month transition period from December 1, 2004, through March 31,
2006. ESI is a load-serving entity and will be billed based on its power
imports
into MISO from PJM during 2002 and 2003. Total exposure for the 16-month
transitional period, taken from proposed compliance filings by the transmission
owners, is approximately $19.2 million total for ESI, of which
$17.4 million is for Michigan and $1.8 million is for Ohio. Through
September 30, 2005, ESI has made payments totaling $10.2 million for these
charges, of which $7.6 million has been expensed.
On
February 10, 2005, the FERC issued an order requesting compliance filings
from
transmission providers implementing the SECA effective December 1, 2004,
subject to refund and surcharge, as appropriate. Public hearings will be
held
regarding the compliance filings. The application and legality of the SECA
is
being challenged by many load-serving entities, including ESI. On February
28,
2005, ESI filed a motion for a Partial Stay of the February 10, 2005, FERC
order, proposing that SECA charges on its Michigan load be postponed until
a
FERC order approves a decision or settlement in the formal hearing proceeding.
The FERC denied this motion on May 4, 2005. On June 3, 2005, ESI filed with
FERC a request for rehearing of the order denying stay. ESI also participated
in
a joint petition to the District of Columbia Circuit Court in an attempt to
obtain a final order from the FERC on rehearing of the initial SECA order.
In
the interim, the exposure will be managed through customer charges and other
available avenues, where feasible. It is probable that ESI's total exposure
will
be reduced by up to $4.8 million because of inconsistencies between the
FERC's SECA order and the transmission owners' compliance filings (upon which
current obligations are based). Resolution of issues to be raised in the
SECA
hearing offer the possibility of further reductions in ESI's exposure, but
the
extent is unknown at present. Through existing contracts, ESI has the ability
to
pass a portion of the SECA charges on to customers and has begun to do so.
Since
SECA is a transition charge ending on March 31, 2006, it does not directly
impact ESI's long-term competitiveness.
The
SECA is also an
issue for WPSC and UPPCO, who have intervened and protested a number of
proposals in this docket because those proposals could result in unjust,
unreasonable, and discriminatory charges for electric customers. It is
anticipated that most of the SECA charges incurred by WPSC and UPPCO and
any
refunds will be passed through customer rates.
Coal
Supply
In
May 2005, WPSC received notification from its coal transportation suppliers
that
extensive maintenance is required on the railroad tracks that lead into and
out
of the Powder River Basin. The notification stated that the maintenance efforts
were expected to result in a 15-20% reduction in the amount of contracted
deliveries of Powder River Basin coal to certain of WPSC's coal generating
facilities through November 2005. Actual coal deliveries in the third quarter
were approximately 15% below the level of deliveries originally contracted.
As a
result of the notification and subsequent reduction in coal deliveries, WPSC
has
continued to take steps to conserve coal usage and has secured some alternative
coal supplies at its affected generation facilities. Although WPSC believes
it
has minimized and will continue to minimize the adverse impact on its fuel
and
purchased power costs, the conservation efforts reduced the capacity factors
of
the coal generating units, requiring WPSC to generate power from higher cost
units and to purchase power through other higher cost generating resources
in
the MISO. At this
time,
WPSC does not
expect the coal shortages to have a significant impact on earnings as costs
related to this matter have been approved for deferral by the PSCW.
Income
Taxes
-American
Jobs
Creation Act of 2004-
On
October 22, 2004, the President of the United States signed into law the
American Jobs Creation Act of 2004 ("2004 Jobs Act"). The 2004 Jobs Act
introduces a new tax deduction, the "United States production activities
deduction." This domestic production provision allows as a deduction an amount
equal to a specified percent of the lesser of the qualified production
activities income of the taxpayer for the taxable year or taxable income
for the
taxable year. The deduction is phased in, providing a deduction of three
percent
of income through 2006, six percent of income through 2009, and nine percent
of
income after 2009. On December 21, 2004, the FASB issued staff position
("FSP") 109-1, effective the same day, on accounting for the effects of the
domestic production deduction provisions. FSP 109-1 said the deduction
should be accounted for as a special deduction rather than a tax rate reduction.
FSP 109-1 also said the special deduction should be considered by an
enterprise in measuring deferred taxes when graduated tax rates are a
significant factor and also in assessing whether a valuation allowance is
necessary. On December 8, 2004, the PSCW issued an order authorizing WPSC
to defer the revenue requirements impacts resulting from the 2004 Jobs Act.
The
Internal Revenue Service and Department of Treasury issued interim guidance
on
January 19, 2005, covering the implementation of the domestic production
provision of the 2004 Jobs Act. WPSC has recorded the estimated tax impact
of
this deduction in its financial statements for the nine months ended
September 30, 2005. However, pursuant to regulatory treatment, the majority
of the tax benefits derived were deferred and will be passed on to customers
in
future rates.
-Section
29 Federal
Tax Credits-
We
have significantly reduced our consolidated federal income tax liability
for the
past four years through tax credits available to us under Section 29 of the
Internal Revenue Code for the production and sale of solid synthetic fuel
from
coal. These tax credits are scheduled to expire at the end of 2007 and are
provided as an incentive for taxpayers to produce fuels from alternate sources
and reduce domestic dependence on imported oil. This incentive is not deemed
necessary if the price of oil increases sufficiently to provide a natural
market
for these fuels. Therefore, the tax credit in a given year is subject to
phase
out if the reference price of oil within that year exceeds a threshold price
set
by the IRS and is eliminated entirely if the reference price increases beyond
a
phase-out price. The reference price of a barrel of oil is an estimate of
the
annual average wellhead price per barrel for domestic crude oil. The threshold
price at which the credit begins to phase out was set in 1980 and is adjusted
annually for inflation; the IRS releases the final numbers for a given year
in
the first part of the following year. For 2004, the reference price was $36.75,
the threshold price was $51.35, and the credits would have been eliminated
had
the reference price exceeded $64.47. For 2005, the estimated threshold price
is
$52.57, and the credits will be eliminated if the reference price exceeds
$65.99.
Numerous
events
have recently increased domestic crude oil prices, including concerns about
terrorism, storm-related supply disruptions, and worldwide demand. Although
we
do not expect the amount of our 2005 Section 29 tax credits to be adversely
affected by oil prices given the current forward price curve for crude oil,
we
cannot predict with any certainty the future price of a barrel of oil.
Therefore, in order to manage exposure to the risk of an increase in oil
prices
that could reduce the amount of 2005, 2006, and 2007 Section 29 tax credits
that
could be recognized, PDI entered into a series of derivative contracts covering
a specified number of barrels of oil. These derivatives mitigate approximately
100%, 95%, and 40% of the Section 29 tax credit exposure in 2005, 2006, and
2007, respectively. The derivative contracts involve purchased and written
call
options that provide for net cash settlement at expiration based on the average
NYMEX trading price of oil in relation to the strike price of each option.
Subsequent to the initial execution date, the 2005 hedged position was optimized
by adjusting the monthly option strike prices upward. Premiums paid, net
of
optimization and settlements, totaled $15.0 million ($0.6 million for 2005
options, $11.1 million for 2006 options, and $3.3 million for 2007
options),
all of
which are recorded in Risk management assets on the balance sheet and will
be
amortized over the applicable periods. The derivative contracts have not
been
designated as hedging instruments and, as a result, changes in the fair value
of
the options are recorded currently in earnings. As of September 30, 2005,
unrealized pre-tax mark-to-market gains of $5.3 million, $5.7 million, and
$4.4 million were recorded for the 2005, 2006, and 2007 options,
respectively, and a $1.9 million gain was realized related to the 2005
contracts.
-Peshtigo
River
Land Donation-
In
2004, WPS Resources submitted a request to have the Internal Revenue
Service conduct a pre-filing review of a tax position related to the 2004
tax
return. The tax position related to the value of the Peshtigo River land
donated
to the WDNR in 2004. A pre-filing review of the land donation deduction was
initiated by the Internal Revenue Service in the first quarter of 2005; however,
in the second quarter, WPS Resources and the Internal Revenue Service
mutually agreed to withdraw this issue from the pre-filing review process,
citing an inability to reach a consensus on the tax treatment and value of
the
land donated. In 2004, WPS Resources recorded a $4.1 million income
tax benefit related to the Peshtigo River land donation. We believe the value
we
placed on the land donated was reasonable and will continue to pursue this
matter if challenged by the Internal Revenue Service upon examination of
the tax
return.
GUARANTEES
AND OFF BALANCE SHEET ARRANGEMENTS - WPS RESOURCES
As
part of normal business, WPS Resources and its subsidiaries enter into
various guarantees providing financial or performance assurance to third
parties
on behalf of certain subsidiaries. These guarantees are entered into primarily
to support or enhance the creditworthiness otherwise attributed to a subsidiary
on a stand-alone basis, thereby facilitating the extension of sufficient
credit
to accomplish the subsidiaries' intended commercial purposes.
The
guarantees
issued by WPS Resources include inter-company guarantees between parents
and their subsidiaries, which are eliminated in consolidation, and guarantees
of
the subsidiaries' own performance. As such, these guarantees are excluded
from
the recognition, measurement, and disclosure requirements of FIN No. 45,
"Guarantors' Accounting and Disclosure Requirements for Guarantees, including
Indirect Guarantees of Indebtedness of Others."
At
September 30, 2005, and December 31, 2004, outstanding guarantees
totaled $1,182.7 million and $977.9 million, respectively, as
follows:
|
|
|
|
|
|
WPS Resources'
Outstanding Guarantees
(Millions)
|
|
September 30,
2005
|
|
December 31,
2004
|
|
Guarantees
of
subsidiary debt
|
|
$
|
27.2
|
|
$
|
27.2
|
|
Guarantees
supporting commodity transactions of subsidiaries
|
|
|
1,073.9
|
|
|
863.9
|
|
Standby
letters of credit
|
|
|
76.0
|
|
|
80.9
|
|
Surety
bonds
|
|
|
0.7
|
|
|
0.6
|
|
Other
guarantee
|
|
|
4.9
|
|
|
5.3
|
|
Total
guarantees
|
|
$
|
1,182.7
|
|
$
|
977.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WPS Resources'
Outstanding Guarantees
(Millions)
Commitments
Expiring
|
|
Total
Amounts
Committed
At
September 30,
2005
|
|
Less
Than
1
Year
|
|
1
to
3
Years
|
|
4
to
5
Years
|
|
Over
5
Years
|
|
Guarantees
of
subsidiary debt
|
|
$
|
27.2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
27.2
|
|
Guarantees
supporting commodity transactions of subsidiaries
|
|
|
1,073.9
|
|
|
896.5
|
|
|
118.2
|
|
|
15.2
|
|
|
44.0
|
|
Standby
letters of credit
|
|
|
76.0
|
|
|
60.4
|
|
|
15.6
|
|
|
-
|
|
|
-
|
|
Surety
bonds
|
|
|
0.7
|
|
|
0.7
|
|
|
.
|
|
|
-
|
|
|
-
|
|
Other
guarantee
|
|
|
4.9
|
|
|
-
|
|
|
-
|
|
|
4.9
|
|
|
-
|
|
Total
guarantees
|
|
$
|
1,182.7
|
|
$
|
957.6
|
|
$
|
133.8
|
|
$
|
20.1
|
|
$
|
71.2
|
|
At
September 30, 2005, WPS Resources had outstanding $27.2 million
in corporate guarantees supporting indebtedness. Of that total,
$27.0 million supports outstanding debt at one of PDI's subsidiaries. The
underlying debt related to these guarantees is reflected on the Condensed
Consolidated Balance Sheet.
At
September 30, 2005, WPS Resources' Board of Directors had authorized
management to issue corporate guarantees in the aggregate amount of up to
$1.2
billion to support the business operations of ESI and PDI. On October 27,
2005,
WPS Resources' Board of Directors authorized an additional $150 million of
corporate guarantees to support the business operations of ESI and PDI bringing
the aggregate amount to $1.35 billion. WPS Resources primarily issues
guarantees for indemnification obligations related to business purchase
agreements and to counterparties in the wholesale electric and natural gas
marketplace to provide counterparties the assurance that ESI and PDI will
perform on their obligations and permit ESI and PDI to operate within these
markets. At September 30, 2005, WPS Resources provided parental
guarantees in the amount of $1,068.9 million, reflected in the above table,
for ESI's and PDI's indemnification obligations for business operations,
including $8.1 million of guarantees that received specific authorization
from WPS Resources' Board of Directors and are not included in the
$1.2 billion general authorized amount. Of the parental guarantees provided
by WPS Resources, the outstanding balance at September 30, 2005, which
WPS Resources would be obligated to support is $261 million.
Another
$5.0 million of corporate guarantees support energy and transmission supply
at UPPCO. In February 2005, WPS Resources' Board of Directors authorized
management to issue corporate guarantees in the aggregate amount of up to
$15.0 million to support the business operations of UPPCO. Corporate
guarantees issued in the future under the Board authorized limit may or may
not
be reflected on WPS Resources' Condensed Consolidated Balance Sheet,
depending on the nature of the guarantee.
At
WPS Resources' request, financial institutions have issued
$76.0 million in standby letters of credit for the benefit of third parties
that have extended credit to certain subsidiaries. If a subsidiary does not
pay
amounts when due under a covered contract, the counterparty may present its
claim for payment to the financial institution, which will request payment
from
WPS Resources. Any amounts owed by our subsidiaries are reflected in the
Condensed Consolidated Balance Sheet.
At
September 30, 2005, WPS Resources furnished $0.7 million of
surety bonds for various reasons including worker compensation coverage and
obtaining various licenses, permits, and rights-of-way. Liabilities incurred
as
a result of activities covered by surety bonds are included in the Condensed
Consolidated Balance Sheet.
The
other guarantee
of $4.9 million listed in the above table was issued by WPSC to indemnify a
third party for exposures related to the construction of utility assets.
This
amount is not reflected on the Condensed Consolidated Balance
Sheet.
As
a result of the unplanned outage of Kewaunee in 2005 and in relation to the
sale
of Kewaunee to Dominion Resources, Inc., See Note 5, Acquisitions
and Sales of Assets,
WPSC and Wisconsin
Power and Light (WP&L) acknowledged that there may be increased capital
expenditures, operating and maintenance expenses, extended outages, and
inspections and related oversight costs that arise from any issues found
as a
result of the design bases documentation review. Therefore, WPSC and WP&L
agreed to indemnify Dominion Resources, Inc. for 70% of any and all reasonable
costs asserted or initiated against, suffered, or otherwise existing, incurred
or accrued, resulting from or arising from the resolution of any design bases
documentation issues that are incurred prior to completion of Kewaunee’s
scheduled maintenance period for 2009 up to a maximum combined exposure of
$15
million for WPSC and WP&L. WPSC believes that it will expend its share of
costs related to this indemnification and, as a result, recorded the fair
value
of the liability on its financial statements.
MARKET
PRICE RISK MANAGEMENT ACTIVITIES - WPS RESOURCES
Market
price risk
management activities include the electric and natural gas marketing and
related
risk management activities of ESI. ESI's marketing and trading operations
manage
power and natural gas procurement as an integrated portfolio with its retail
and
wholesale sales commitments. Derivative instruments are utilized in these
operations. ESI measures the fair value of derivative instruments (including
NYMEX exchange and over-the-counter contracts, natural gas options, natural
gas
and electric power physical fixed price contracts, basis contracts, and related
financial instruments) on a mark-to-market basis. The fair value of derivatives
is shown as "assets or liabilities from risk management activities" in the
Condensed Consolidated Balance Sheets.
The
offsetting
entry to assets or liabilities from risk management activities is to other
comprehensive income or earnings, depending on the use of the derivative,
how it
is designated, and if it qualifies for hedge accounting. The fair values
of
derivative instruments are adjusted each reporting period using various market
sources and risk management systems. The primary input for natural gas pricing
is the settled forward price curve of the NYMEX exchange, which includes
contracts and options. Basis pricing is derived from published indices and
documented broker quotes. ESI bases electric prices on published indices
and
documented broker quotes. The following table provides an assessment of the
factors impacting the change in the net value of ESI's assets and liabilities
from risk management activities for the nine months ended
September 30, 2005.
|
|
|
|
|
|
|
|
ESI
Mark-to-Market Roll Forward
(Millions)
|
|
Natural
Gas
|
|
Electric
|
|
Total
|
|
|
|
|
|
|
|
|
|
Fair
value of
contracts at December 31, 2004
|
|
$
|
31.6
|
|
$
|
13.7
|
|
$
|
45.3
|
|
Less
-
contracts realized or settled during period
|
|
|
9.5
|
|
|
(4.8
|
)
|
|
4.7
|
|
Plus
-
changes in fair value of contracts in existence
at
September 30, 2005
|
|
|
(73.3
|
)
|
|
(6.4
|
)
|
|
(79.7
|
)
|
Fair
value of
contracts at September 30, 2005
|
|
$
|
(51.2
|
)
|
$
|
12.1
|
|
$
|
(39.1
|
)
|
The
fair value of
contracts at December 31, 2004, and September 30, 2005, reflects the
values reported on the balance sheet for net mark-to-market current and
long-term risk management assets and liabilities as of those dates. Contracts
realized or settled during the period includes the value of contracts in
existence at December 31, 2004, that were no longer included in the net
mark-to-market assets as of September 30, 2005, along with the amortization
of those derivatives later designated as normal purchases and sales under
SFAS
No. 133. Changes in fair value of existing contracts include unrealized
gains and losses on contracts that existed at December 31, 2004, and
contracts that were entered into subsequent to December 31, 2004, which are
included in ESI's portfolio at September 30, 2005. There were, in many
cases, offsetting positions entered into and settled during the period resulting
in gains or losses being realized during the current period. The realized
gains
or losses from these offsetting positions are not reflected in the table
above.
Market
quotes are
more readily available for short duration contracts. The table below shows
the
sources of fair value and maturity of ESI's risk management
instruments.
|
|
|
|
|
|
|
|
|
|
|
|
ESI
Risk
Management Contract Aging at Fair Value
As
of
September 30, 2005
Source
of
Fair Value (Millions)
|
|
Maturity
Less
Than
1
Year
|
|
Maturity
1 to
3
Years
|
|
Maturity
4 to 5
Years
|
|
Maturity
in
Excess
of
5
Years
|
|
Total
Fair
Value
|
|
Prices
actively quoted
|
|
$
|
(58.2
|
)
|
$
|
6.3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(51.9
|
)
|
Prices
provided by external sources
|
|
|
5.7
|
|
|
6.3
|
|
|
-
|
|
|
-
|
|
|
12.0
|
|
Prices
based
on models and other
valuation
methods
|
|
|
0.8
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.8
|
|
Total
fair
value
|
|
$
|
(51.7
|
)
|
$
|
12.6
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(39.1
|
)
|
We
derive the pricing for most contracts in the above table from active quotes
or
external sources. "Prices actively quoted" includes NYMEX contracts and basis
swaps. "Prices provided by external sources" includes electric and natural
gas
contract positions for which pricing information is obtained primarily through
broker quotes. "Prices based on models and other valuation methods" includes
electric contracts for which reliable external pricing information does not
exist.
ESI
employs a
variety of physical and financial instruments offered in the marketplace
to
limit risk exposure associated with fluctuating commodity prices and volumes,
enhance value, and minimize cash flow volatility. However, the application
of
SFAS No. 133 and its related hedge accounting rules causes ESI to experience
earnings volatility associated with electric and natural gas operations.
While
risks associated with power generating capacity and power and natural gas
sales
are economically hedged, certain transactions do not meet the definition
of a
derivative or do not qualify for hedge accounting under generally accepted
accounting principles. Consequently, gains and losses from these contracts
may
not match with the related physical and financial hedging instruments in
some
reporting periods. The result can cause volatility in ESI's reported
period-by-period earnings; however, the financial impact of this timing
difference will reverse at the time of physical delivery and/or settlement.
The
accounting treatment does not impact the underlying cash flows or economics
of
these transactions. In addition, the natural gas storage cycle can cause
earnings volatility. See Results
of
Operations - Overview of Nonregulated Operations - ESI's Segment
Operations
for information
regarding the natural gas storage cycle.
CRITICAL
ACCOUNTING POLICIES - WPS RESOURCES
In
accordance with the rules proposed by the SEC in May 2002, we reviewed our
critical accounting policies for new critical accounting estimates and other
significant changes. We found that the disclosures made in our Annual Report
on
Form 10-K for the year ended December 31, 2004, as updated by our Current
Report on Form 8-K dated August 25, 2005, are still current and that there
have
been no significant changes.
RESULTS
OF
OPERATIONS - WPSC
WPSC
is a regulated
electric and natural gas utility as well as a holding company exempt
from the
Public Utility Holding Company Act of 1935. Electric operations accounted
for
approximately 68% of revenues for the nine months ended September 30, 2005,
while natural gas operations accounted for 32% of revenues for the nine
months
ended September 30, 2005.
Third
Quarter 2005 Compared with Third Quarter 2004
WPSC
Overview
WPSC's
results of
operations for the quarters ended September 30 are shown in the following
table:
|
|
|
|
|
|
|
|
WPSC's
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
338.5
|
|
$
|
260.2
|
|
|
30.1
|
%
|
Earnings
on
common stock
|
|
$
|
25.7
|
|
$
|
30.5
|
|
|
(15.7
|
%)
|
Electric
utility
revenue increased $52.1 million (24.3%), primarily due to higher electric
sales volumes (related to warmer summer weather conditions and new power
sales
agreements with several wholesale customers), and an approved retail
electric
rate increase. Gas utility revenue increased $26.2 million (57.5%) due to
an increase in the per-unit cost of natural gas, higher natural gas throughput
volumes, and an approved rate increase. Revenue changes by reportable
segment
are discussed in more detail below.
Earnings
from
electric utility operations were $26.7 million for the third quarter of
2005, compared to $31.5 million for the third quarter of 2004, largely due
to WPSC experiencing higher fuel and purchased power costs than it was
able to
recover from ratepayers, as explained in more detail below. Earnings
were also
negatively impacted because certain costs incurred in the third quarter
of 2005
related to plant outages, carrying costs on capital additions, and other
costs
(which are recovered in rates relatively evenly throughout the year)
were
partially recovered in revenue during the first six months of the year,
leading
to higher earnings in those periods.
The
net loss from
gas utility operations was $3.5 million for the third quarter of 2005,
compared to a loss of $3.3 million for the third quarter of 2004. Although
the gas utility margin increased $2.4 million due primarily to the rate
increase and the increase in sales volumes, higher operating expenses
drove the
increased net loss.
Electric
Utility Operations
|
|
|
|
|
|
Three
Months
Ended September 30,
|
|
Electric
Utility Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
266.7
|
|
$
|
214.6
|
|
|
24.3
|
%
|
Fuel
and
purchased power
|
|
|
131.1
|
|
|
62.4
|
|
|
110.1
|
%
|
Margin
|
|
$
|
135.6
|
|
$
|
152.2
|
|
|
(10.9
|
%)
|
Sales
in
kilowatt-hours
|
|
|
3,916.0
|
|
|
3,487.3
|
|
|
12.3
|
%
|
WPSC's
electric
utility revenue increased $52.1 million (24.3%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
Electric utility revenue increased largely due to an increase in electric
sales
volumes and an approved electric rate increase for WPSC's Wisconsin retail
customers. Electric sales volumes increased 12.3%, primarily due to
significantly warmer weather in the third quarter of 2005, compared to
the third
quarter of 2004, and new power sales agreements that were entered into
with
wholesale customers. As a result of the warm weather, WPSC set all-time
records
for peak electric demand in the third quarter of 2005. On December 21,
2004, the PSCW approved a
retail
electric
rate increase of $60.7 million (8.6%), effective January 1, 2005. The rate
increase was required primarily to recover increased costs related to
fuel and
purchased power, costs related to the construction of the Weston 4 base-load
generation facility, and benefit costs.
WPSC's
electric
utility margin decreased $16.6 million (10.9%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
The decreased margin was largely driven by the sale of Kewaunee on July
5, 2005
and the related power purchase agreement. Prior to the sale of Kewaunee,
only
nuclear fuel expense was reported as a component of fuel and purchased
power
costs. Subsequent to the sale all payments to Dominion Energy Kewaunee,
LLC for
power purchased from Kewaunee are reported as components of fuel and
purchased
power costs. These include both variable payments for energy delivered
and fixed
payments. As a result of the sale, WPSC no longer incurs operating and
maintenance expense, depreciation and decommissioning expense, or interest
expense for Kewaunee. Excluding the $21.0 million of fixed payments made to
Dominion Energy Kewaunee, LLC in the third quarter of 2005, the electric
utility
margin increased $4.4 million, compared to the same period in the prior
year. This increase was driven by the increase in electric sales volumes
and the
rate increase discussed above, but was largely offset by higher per-unit
fuel
and purchased power costs.
The
quantity of
power purchased by WPSC during the quarter ended September 30, 2005,
increased approximately 168% compared to the same quarter in 2004, and
fuel and
purchased power costs were approximately 68% higher on a per-unit basis.
The
increase in the quantity of power purchased was largely due to power
purchased
from Dominion Energy Kewaunee, LLC as previously discussed, warm weather
conditions, WPSC's need to conserve coal because of coal supply issues
(see
Other
Future
Considerations),
and a planned
outage at WPSC's Weston 3 generation plant that began in the third quarter
of
2005. The increase in the per-unit cost of fuel and purchased power was
driven
by the sale of Kewaunee (primarily related to $21.0 million of fixed
payments being recorded as a component of fuel and purchased power costs),
congestions charges and line loss charges that were not fully offset
by credits
from MISO, increased coal costs related to procurement of coal from alternate
sources, and the need to supply more energy from higher cost peaking
units due
to warm weather conditions, coal conservation efforts, and a planned
outage at
WPSC's Weston 3 generation plant that began in the third quarter of 2005.
The
PSCW approved the deferral of increased fuel and purchased power costs
related
to the MISO and coal supply matters discussed above and WPSC deferred
$15.9 million of costs related to these issues in the third quarter of
2005. Excluding deferred costs, fuel and purchased power costs at WPSC
increased
$68.7 million. As discussed above, approximately $21.0 million of the
increase in purchased power costs related to the Kewaunee fixed payments.
Excluding these fixed payments, fuel and purchased power costs at WPSC
increased
$47.7 million and total fuel and purchased power costs incurred during the
quarter exceeded the amount recovered from ratepayers (as approved in
the 2005
rate case) and, therefore, had a negative impact on margin.
The
PSCW allows
WPSC to adjust prospectively the amount billed to Wisconsin retail customers
for
fuel and purchased power if costs are above or below approved levels
by more
than 2% on an annualized basis. At June 30, 2005, WPSC was experiencing
fuel and purchased power costs that were more than 2% lower than the
approved
level. However, primarily because of the high cost of natural gas resulting
from
the impact hurricanes had on natural gas supply, in combination with
the need to
run the natural gas-fired
peaker
units more in the third quarter, at September 30, 2005, WPSC projects that
actual fuel and purchased power costs for 2005 could be significantly
higher
than what was allowed in the rate 2005 case.
Electric
utility
earnings decreased $4.8 million (15.2%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004,
largely driven by the higher fuel and purchased power costs discussed
above.
Earnings were also negatively impacted because certain costs incurred
in the
third quarter of 2005 related to plant outages, carrying costs on capital
additions, and other costs (which are recovered in rates relatively evenly
throughout the year) were partially recovered in revenue during the first
six
months of the year, leading to higher earnings in those periods.
Gas
Utility
Operations
|
|
|
|
|
|
Three
Months
Ended September 30,
|
|
Gas
Utility
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
71.8
|
|
$
|
45.6
|
|
|
57.5
|
%
|
Purchase
costs
|
|
|
52.6
|
|
|
28.8
|
|
|
82.6
|
%
|
Margins
|
|
$
|
19.2
|
|
$
|
16.8
|
|
|
14.3
|
%
|
Throughput
in
therms
|
|
|
128.6
|
|
|
104.1
|
|
|
23.5
|
%
|
Gas
utility revenue
increased $26.2 million (57.5%) for the quarter ended September 30,
2005, compared to the quarter ended September 30, 2004. Gas utility
revenue increased primarily as a result of an increase in the per-unit
cost of
natural gas, higher natural gas throughput volumes, and a rate increase.
Natural
gas costs increased 15.6% (on a per-unit basis) for the quarter ended
September 30, 2005, compared to the quarter ended September 30, 2004.
Following regulatory practice, WPSC passes changes in the total cost
of natural
gas on to customers through a purchased gas adjustment clause, as allowed
by the
PSCW and the MPSC. Natural gas throughput volumes increased 23.5%, primarily
related to an increase in interdepartmental sales from the natural gas
utility
to the electric utility as a result of increased electric generation
from
natural gas fired combustion turbines. The PSCW issued a final order
authorizing
a natural gas rate increase of $5.6 million (1.1%), effective January
1, 2005. The rate increase was primarily driven by higher benefit costs
and
the cost of distribution system improvements.
The
natural gas
utility margin increased $2.4 million (14.3%) for the quarter ended
September 30, 2005, compared to the quarter ended September 30,
2004. The higher natural gas utility margin was largely due to the rate
increase
mentioned above. The increase in interdepartmental sales volumes to WPSC's
electric utility also had a positive impact on the natural gas
margin.
The
gas utility
realized a net loss of $3.5 million for the quarter ended
September 30, 2005, compared to a net loss of $3.3 million for the
quarter ended September 30, 2004. The higher net loss was attributed to an
increase in operating and maintenance expenses and depreciation expense
incurred
by the gas utility.
Operating
Expenses
|
|
|
|
|
|
Three
Months
Ended September 30,
|
|
Operating
Expenses (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
82.1
|
|
$
|
88.8
|
|
|
(7.5
|
%)
|
Depreciation
and decommissioning expense
|
|
|
19.7
|
|
|
21.9
|
|
|
(10.0
|
%)
|
Operating
and
Maintenance Expense
WPSC's
operating
and maintenance expenses decreased $6.7 million, driven by a
$10.0 million decrease in operating and maintenance expenses related to
Kewaunee. WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee,
LLC on July 5, 2005 and currently purchases 59% of the output from this
facility
through a power purchase agreement. The decrease in operating and maintenance
expenses as a result of the Kewaunee sale were partially offset by increases
in
transmission costs and pension and postretirement expense.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $2.2 million (10.0%) for the quarter
ended September 30, 2005, compared to the quarter ended September 30,
2004, driven by a $3.1 million decrease in depreciation expense related to
the Kewaunee assets (which were sold to Dominion Energy Kewaunee, LLC
in July
2005) and lower gains on decommissioning trust assets, partially offset
by
additional
depreciation due to continued capital investment. Realized gains on
decommissioning trust assets are partially offset by decommissioning
expense
pursuant to regulatory practice.
Nine
Months
2005 Compared With Nine Months 2004
WPSC
Overview
WPSC's
results of
operations for the nine months ended September 30 are shown in the
following table:
|
|
|
|
|
|
|
|
WPSC's
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
1,042.0
|
|
$
|
892.0
|
|
|
16.8
|
%
|
Earnings
on
common stock
|
|
$
|
84.6
|
|
$
|
74.9
|
|
|
13.0
|
%
|
Electric
utility
revenue increased $102.6 million (17.0%), primarily due to an approved
retail electric rate increase, and higher electric sales volumes related
to
warmer summer weather conditions and new power sales agreements with
wholesale
customers. Gas utility revenue increased $47.4 million (16.4%) due
primarily to an increase in the per-unit cost of natural gas, an approved
rate
increase, and higher natural gas throughput volumes. Revenue changes
by
reportable segment are discussed in more detail below.
Earnings
from
electric utility operations were $69.7 million for the nine months ended
September 30, 2005, compared to $58.1 million for the same period in
2004. Warmer temperatures during the cooling season in 2005, compared
to 2004,
and a retail electric rate increase favorably impacted WPSC's electric
margin;
however, partially offsetting these increases was the negative impact
of rising
natural gas prices in the third quarter of 2005.
Earnings
from gas
utility operations were $8.6 million during the nine months ended
September 30, 2005, compared to $9.9 million for the same period in
2004. Although the gas utility margin increased $3.7 million due primarily
to a small rate increase and higher throughput volumes, higher operating
expenses drove the decrease in earnings from gas utility
operations.
Electric
Utility Operations
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
Electric
Utility Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
705.8
|
|
$
|
603.2
|
|
|
17.0
|
%
|
Fuel
and
purchased power
|
|
|
270.1
|
|
|
184.2
|
|
|
46.6
|
%
|
Margins
|
|
$
|
435.7
|
|
$
|
419.0
|
|
|
4.0
|
%
|
Sales
in
kilowatt-hours
|
|
|
10,878.5
|
|
|
10,067.6
|
|
|
8.1
|
%
|
WPSC's
electric
utility revenue increased $102.6 million (17.0%) for the nine months ended
September 30, 2005, compared to the nine months ended September 30,
2004, largely due to an approved electric rate increase for WPSC's Wisconsin
retail customers and an increase in electric sales volumes. On December 21,
2004, the PSCW approved a retail electric rate increase of $60.7 million
(8.6%), effective January 1, 2005. Electric sales volumes increased 8.1%,
primarily due to significantly warmer weather during the second and third
quarters of 2005, compared to the same periods in 2004, and new power
sales
agreements that were entered into with wholesale customers. As a result
of the
warm weather, WPSC set all-time records for peak electric demand in the
second
and third quarters of 2005.
WPSC's
electric
margin increased $16.7 million ($37.7 million if the
$21.0 million fixed payment made for power purchased from Dominion Energy
Kewaunee, LLC in the third quarter of 2005 was excluded),
which
was primarily
driven by the retail electric rate increase and the increase in electric
sales
volumes discussed above.
The
quantity of
power purchased by WPSC during the nine months ended September 30, 2005,
increased 95% compared to the nine months ended September 30, 2004, and
fuel and purchased power costs were approximately 47% higher on a per-unit
basis. The increase in the quantity of power purchased was largely due
to an
unscheduled outage at Kewaunee, which began in February 2005 (with this
unit
returning to service just prior to the sale of this facility to Dominion
Energy
Kewaunee, LLC on July 5, 2005), power purchased from Dominion Energy
Kewaunee,
LLC as previously discussed, warm weather conditions, and coal conservation
efforts. The increase in the per-unit cost of fuel and purchased power
was
driven by the Kewaunee sale (primarily related to the $21.0 million of
fixed payments recorded as a component of fuel and purchased power costs),
congestion charges and line loss charges that were not fully offset by
credits
from MISO, the need to supply more energy from higher cost peaking units
due to
warm weather conditions and coal conservation efforts, and the rising
price of
natural gas used as fuel for the peaking units. The unscheduled 2005
outage at
Kewaunee did not have a significant impact on the electric utility margin
as the
PSCW approved deferral of unanticipated fuel and purchased power costs
directly
related to the outage. For the nine months ended September 30, 2005,
$46.2 million of fuel and purchased power costs were deferred in
conjunction with the Kewaunee outage. The PSCW also approved the deferral
of
increased fuel and purchased power costs related to the MISO and coal
supply
matters, and WPSC deferred $16.3 million of costs related to these issues
during the nine months ended September 30, 2005. Excluding deferred costs,
fuel and purchased power costs at WPSC increased $85.9 million for the nine
months ended September 30, 2005, compared to the same period in 2004,
primarily related to the significant increase in natural gas prices after
the
hurricanes disrupted natural gas supply. As discussed above, approximately
$21.0 million of the increase in purchased power costs related to the
Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased
power costs at WPSC increased $64.9 million and total fuel and purchased
power costs incurred during the nine months ended September 30, 2005
exceeded the amount recovered from ratepayers (as approved in the 2005
rate
case), therefore, having a negative impact on margin.
Warmer
temperatures
during the cooling season in 2005, compared to 2004, and a retail electric
rate
increase favorably impacted WPSC's electric margin, contributing to an
$11.6 million increase in electric utility earnings; however, the increase
in electric utility earnings at WPSC was partially offset in the third
quarter
of 2005 by rising natural gas prices, which have not been deferred.
Gas
Utility
Operations
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
Gas
Utility
Results (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
336.2
|
|
$
|
288.8
|
|
|
16.4
|
%
|
Purchase
costs
|
|
|
247.1
|
|
|
203.4
|
|
|
21.5
|
%
|
Margins
|
|
$
|
89.1
|
|
$
|
85.4
|
|
|
4.3
|
%
|
Throughput
in
therms
|
|
|
599.9
|
|
|
571.1
|
|
|
5.0
|
%
|
Gas
utility revenue
increased $47.4 million (16.4%) for the nine months ended
September 30, 2005, compared to the nine months ended
September 30, 2004. Gas utility revenue increased primarily as a
result of an increase in the per-unit cost of natural gas, a natural
gas rate
increase, and higher natural gas throughput volumes. Natural gas costs
increased
12.5% (on a per-unit basis) for the nine months ended September 30, 2005,
compared to the same period in 2004. The PSCW issued a final order authorizing
a
natural gas rate increase of $5.6 million (1.1%), effective
January 1, 2005. Natural gas throughput volumes increased 5.0%,
primarily related to an increase in interdepartmental sales from the
natural gas
utility to the electric utility as a result of increased generation from
combustion turbines. The combustion turbines were dispatched more often
due to
the Kewaunee outage, warm weather conditions, and coal conservation efforts.
Higher natural gas throughput volumes from interdepartmental sales to
the
electric
utility
were
partially offset by lower natural gas throughput volumes to residential
customers, related primarily to milder weather in the first half of 2005,
compared to the same period in 2004.
The
natural gas
utility margin increased $3.7 million (4.3%) for the nine months ended
September 30, 2005, compared to the nine months ended
September 30, 2004. The higher natural gas utility margin was largely due
to the rate increase mentioned above. The increase in interdepartmental
sales
volumes to WPSC's electric utility also had a positive impact on the
natural gas
margin.
Income
available
for common shareholders attributed to the gas utility decreased
$1.3 million (13.1%). The higher margin was more than offset by an increase
in operating and maintenance expenses at the gas utility.
Operating
Expenses
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
WPSC
(Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
Operating
and
maintenance expense
|
|
$
|
281.1
|
|
$
|
283.6
|
|
|
(0.9
|
%)
|
Depreciation
and decommissioning expense
|
|
|
107.0
|
|
|
66.7
|
|
|
60.4
|
%
|
Federal
income taxes
|
|
|
23.7
|
|
|
30.5
|
|
|
(22.3
|
%)
|
State
income
taxes
|
|
|
7.2
|
|
|
8.6
|
|
|
(16.3
|
%)
|
Other
Income
|
|
|
|
|
|
Nine
Months
Ended September 30,
|
|
Other
Income
and (Deductions) (Millions)
|
|
2005
|
|
2004
|
|
Change
|
|
|
|
|
|
|
|
|
|
Allowance
for
equity funds used during construction
|
|
$
|
1.3
|
|
$
|
1.5
|
|
|
(13.3
|
%)
|
Other,
net
|
|
|
51.2
|
|
|
14.9
|
|
|
243.6
|
%
|
Income
taxes
|
|
|
(16.8
|
)
|
|
(2.2
|
)
|
|
663.6
|
%
|
Operating
and
Maintenance Expense
Operating
and
maintenance expense at WPSC decreased $2.5 million, driven by a
$10.0 million decrease related to Kewaunee in the third quarter of 2005,
compared to the third quarter of 2004. WPSC sold its 59% interest in
Kewaunee to
Dominion Energy Kewaunee, LLC on July 5, 2005, and currently purchases
59% of
the output of this facility from Dominion Energy Kewaunee, LLC through
a power
purchase agreement. The decrease in operating and maintenance expenses
as a
result of the Kewaunee sale were partially offset by increases in transmission
costs and pension and postretirement expense. The unplanned outage at
Kewaunee
earlier in 2005 did not significantly impact the period-over-period change
in
operating and maintenance expenses as the PSCW approved the deferral
of
incremental operating and maintenance expenses that were incurred as
a direct
result of the unplanned outage. Operating and maintenance costs of
$11.6 million were deferred during the nine months ended September 30,
2005 related to this outage.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense increased $40.3 million (60.4%) for the nine months
ended September 30, 2005, compared to the nine months ended
September 30, 2004. Approximately $38 million of the increase resulted
from increased gains on decommissioning trust assets. The remaining increase
related to continued capital investment, partially offset by a decrease
in
depreciation relating to Kewaunee due to the sale of this facility in
July 2005.
Realized gains on decommissioning trust assets are partially offset by
decommissioning expense pursuant to regulatory practice as discussed
in more
detail in Federal
Income
Taxes/State Income Taxes/Other Income,
below.
Federal
Income
Taxes/State Income Taxes/Other Income
The
period-over-period change in these account balances was primarily related
to the
realized gains recognized on the nonqualified decommissioning trust assets
in
the second quarter of 2005. Approximately $38 million of the increase in
other income related to the realized gains on the nonqualified decommissioning
trust assets. The nonqualified nuclear decommissioning trust assets were
placed
in more conservative investments in the second quarter in anticipation
of the
sale of Kewaunee, which closed on July 5, 2005. Pursuant to regulatory
practice,
the increase in miscellaneous income related to the realized gains was
offset by
an increase in decommissioning expense. Income tax expense related to
the
realized gains was offset by a deferred tax benefit related to the
decommissioning expense. Overall, the change in the investment strategy
for the
nonqualified decommissioning trust assets had no impact on earnings,
as
summarized in the table below.
|
|
|
|
(Millions)
|
|
Income/(Expense)
|
|
|
|
|
|
Depreciation
and decommissioning expense
|
|
$
|
(38
|
)
|
Federal
income taxes
|
|
|
13
|
|
State
income
taxes
|
|
|
2
|
|
Other,
net
|
|
|
38
|
|
Income
taxes
|
|
|
(15
|
)
|
Total
earnings impact
|
|
$
|
-
|
|
LIQUIDITY
AND CAPITAL RESOURCES - WPSC
WPSC
believes that
its cash, operating cash flows, and borrowing ability because of strong
credit
ratings, when taken together, provide adequate resources to fund ongoing
operating requirements and future capital expenditures related to expansion
of
existing businesses and development of new projects. However, WPSC's
operating
cash flow and access to capital markets can be impacted by macroeconomic
factors
outside its control. In addition, WPSC's borrowing costs can be impacted
by its
short- and long-term debt ratings assigned by independent rating agencies,
which
in part are based on certain credit measures such as interest coverage
and
leverage ratios. Currently, WPSC believes these ratings continue to be
among the
best in the energy industry (see the Financing
Cash
Flows,
Credit
Ratings
section below).
Operating
Cash Flows
During
the nine
months ended September 30, 2005, net cash provided by operating activities
was $136.0 million, compared with $205.7 million during the nine
months ended September 30, 2004. The decrease in cash provided by operating
activities is primarily due to increased expenditures associated with
the spring
2005 Kewaunee outage. These expenditures were accounted for as deferred
expenses
in accordance with regulatory approval and will be recovered from customers
under future rate orders.
Investing
Cash Flows
Net
cash used for
investing activities was $44.6 million during the nine months ended
September 30, 2005, compared to $169.0 million during the nine months
ended September 30, 2004. The decrease in cash used for investing
activities is due to proceeds of $112.5 million and $127.1 million
received from the sale of Kewaunee and liquidation of the non-qualified
decommissioning trust, respectively, partially offset by a $98.5 million
increase in capital expenditures, mostly due to the construction of Weston
4.
See Note 5, Acquisitions
and Sales of Assets,
for more
information regarding the sale of Kewaunee.
Capital
Expenditures
Capital
expenditures by business segment for the six months ended September 30 are
as follows:
|
|
|
|
|
|
(Millions)
|
|
2005
|
|
2004
|
|
Electric
utility
|
|
$
|
258.7
|
|
$
|
135.2
|
|
Gas
utility
|
|
|
25.2
|
|
|
47.6
|
|
Other
|
|
|
-
|
|
|
2.6
|
|
WPSC
consolidated
|
|
$
|
283.9
|
|
$
|
185.4
|
|
The
increase in
capital expenditures at the electric utility for the nine months ended
September 30, 2005, as compared to the same period in 2004 is mainly due to
higher capital expenditures associated with the construction of Weston
4. Gas
utility capital expenditures decreased primarily due to completion of
the
automated meter-reading project.
Dairyland
Power
Cooperative has confirmed its intent to purchase an interest in Weston
4,
subject to a number of conditions. If the purchase is completed, the
electric
utility expenditures made by WPSC for Weston 4 would be reduced by 30
percent.
The agreement with Dairyland Power Cooperative is part of our continuing
plan to
provide least-cost, reliable energy for the increasing electric demand
of our
customers. We expect to close on this transaction by the end of
2005.
Financing
Cash Flows
Net
cash used for
financing activities was $90.9 million during the nine months ended
September 30, 2005, compared to $36.1 million during the nine months
ended September 30, 2004. This $54.8 million increase in cash used for
financing activities is attributed to increased repayments of commercial
paper
in 2005, partially offset by the repayment of long-term debt in
2004.
Under
a PSCW order,
WPSC may not pay normal common stock dividends of more than 109% of the
previous
year's common stock dividend without the PSCW's approval. In addition,
WPSC's
Restated Articles of Incorporation limit the amount of common stock dividends
that WPSC can pay to certain percentages of its prior 12-month net income,
if
its common stock and common stock surplus accounts constitute less than
25% of
its total capitalization.
Significant
Financing Activities
See
Liquidity
and
Capital Resources
- WPS Resources
for
detailed
information on significant financing activities for WPSC.
Credit
Ratings
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on WPSC's credit ratings.
Future
Capital Requirements and Resources
Contractual
Obligations
The
following table
summarizes the contractual obligations of WPSC, including its subsidiary.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
Due
By Period
|
|
Contractual
Obligations
As
of
September 30, 2005
(Millions)
|
|
Total
Amounts
Committed
|
|
Less
Than
1
Year
|
|
1
to
3
Years
|
|
3
to
5
Years
|
|
Over
5
Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt principal and interest payments
|
|
$
|
746.2
|
|
$
|
13.5
|
|
$
|
54.1
|
|
$
|
54.1
|
|
$
|
624.5
|
|
Operating
lease obligations
|
|
|
13.9
|
|
|
0.9
|
|
|
4.7
|
|
|
3.4
|
|
|
4.9
|
|
Commodity
purchase obligations
|
|
|
1,949.2
|
|
|
76.5
|
|
|
552.9
|
|
|
435.0
|
|
|
884.8
|
|
Purchase
orders
|
|
|
471.6
|
|
|
256.3
|
|
|
184.4
|
|
|
30.9
|
|
|
-
|
|
Other
|
|
|
404.5
|
|
|
20.4
|
|
|
87.3
|
|
|
49.2
|
|
|
247.6
|
|
Total
contractual cash obligations
|
|
$
|
3,585.4
|
|
$
|
367.6
|
|
$
|
883.4
|
|
$
|
572.6
|
|
$
|
1,761.8
|
|
Long-term
debt
principal and interest payments represent bonds issued, notes issued,
and loans
made to WPSC. We record all principal obligations on the balance sheet.
Commodity purchase obligations represent mainly commodity purchase contracts
of
WPSC. WPSC expects to recover the costs of its contracts in future customer
rates. Purchase orders include obligations related to normal business
operations
and large construction obligations, including 100% of Weston 4 obligations;
however, we expect 30% of these costs to be paid by Dairyland Power Cooperative
after the close of Dairyland's purchase of 30% of Weston 4, which is
expected to
close late in 2005. Included in the purchase orders listed in the table
above,
is $301.2 million related to Weston 4 purchase obligations. Other represents
expected pension and post-retirement funding obligations.
Capital
Requirements
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on capital requirements for WPSC.
Capital
Resources
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on capital resources for WPSC.
Other
Future Considerations
Kewaunee
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on the sale of WPSC's interest in Kewaunee.
Regulatory
For
a discussion of
regulatory considerations, see Note 16, Regulatory
Environment.
Industry
Restructuring
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on MISO.
Seams
Elimination Charge Adjustment
See
Liquidity
and
Capital Resources - WPS Resources
for information on
the impact of the Seams Elimination Charge Adjustment on WPSC.
Coal
Supply
See
Liquidity
and
Capital Resources - WPS Resources
for detailed
information regarding WPSC's coal supply.
American
Jobs
Creation Act of 2004
See
Liquidity
and
Capital Resources
- WPS Resources
for detailed
information on the American Jobs Creation Act of 2004.
OFF
BALANCE
SHEET ARRANGEMENTS - WPSC
See
Guarantees
and
Off Balance Sheet Arrangements - WPS Resources
for detailed
information on WPSC's off balance sheet arrangements.
CRITICAL
ACCOUNTING POLICIES - WPSC
In
accordance with the rules proposed by the SEC in May 2002, we reviewed
our
critical accounting policies for new critical accounting estimates and
other
significant changes. We found that the disclosures made in our Annual
Report on
Form 10-K for the year ended December 31, 2004, are still current and that
there have been no significant changes.