WPS RESOURCES
CORPORATION AND SUBSIDIARIES
WISCONSIN
PUBLIC SERVICE CORPORATION AND SUBSIDIARY
June 30,
2006
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. The only significant
reclassification was related to discontinued operations, which is discussed
below. We have condensed or omitted certain financial information and footnote
disclosures normally included in our annual audited financial statements.
These
condensed 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, 2005.
Effective
April 1,
2006, the assets and liabilities, results of operations, and cash flows of
MGUC
were included in WPS Resources' consolidated financial statements. See Note
5, "Acquisitions
and Sales of Assets,"
for more
information.
For
all periods
presented, certain assets and liabilities of Sunbury have been reclassified
as
held for sale and Sunbury's results of operations and cash flows have been
reclassified as discontinued operations. See Note 4, "Sunbury,"
for more
information.
NOTE
2--CASH AND CASH EQUIVALENTS
Short-term
investments with an original maturity of three months or less are reported
as cash equivalents.
The
following is
supplemental disclosure to the WPS Resources and WPSC Condensed
Consolidated Statements of Cash Flows:
(Millions)
|
|
Six
Months
Ended June 30
|
|
WPS Resources
|
|
2006
|
|
2005
|
|
Cash
paid for
interest
|
|
$
|
35.7
|
|
$
|
31.3
|
|
Cash
paid for
income taxes
|
|
$
|
20.5
|
|
$
|
35.2
|
|
|
|
|
|
|
|
|
|
WPSC
|
|
|
|
|
|
|
|
Cash
paid for
interest
|
|
$
|
16.0
|
|
$
|
15.3
|
|
Cash
paid for
income taxes
|
|
$
|
16.0
|
|
$
|
18.1
|
|
During
the six
months ended June 30, 2006, and June 30, 2005, accounts payable
related to Weston 4 construction costs increased approximately $5.6 million
and $22.7 million, respectively, and accordingly, were treated as non-cash
investing activities. Purchase price adjustments totaling $26.0 million
(related to the acquisition by MGUC of the natural gas distribution operations
in Michigan) were funded through accounts payable and were also treated as
non-cash investing activities during the six months ended
June 30, 2006.
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.
WPS Resources classifies mark-to-market gains and losses on derivative
instruments not qualifying for hedge accounting as a component of revenues.
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)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Utility
Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
7.0
|
|
$
|
22.0
|
|
$
|
8.4
|
|
$
|
-
|
|
Financial transmission rights
|
|
|
24.7
|
|
|
14.5
|
|
|
1.7
|
|
|
1.8
|
|
Nonregulated
Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and foreign currency
contracts
|
|
|
972.7
|
|
|
1,058.6
|
|
|
860.2
|
|
|
971.7
|
|
Fair
value hedges - commodity contracts
|
|
|
3.7
|
|
|
4.2
|
|
|
0.5
|
|
|
12.9
|
|
Cash
flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
66.6
|
|
|
33.6
|
|
|
25.1
|
|
|
50.1
|
|
Interest rate swaps
|
|
|
9.3
|
|
|
-
|
|
|
2.3
|
|
|
4.7
|
|
Total
|
|
$
|
1,084.0
|
|
$
|
1,132.9
|
|
$
|
898.2
|
|
$
|
1,041.2
|
|
Balance
Sheet Presentation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
801.4
|
|
$
|
906.4
|
|
$
|
670.1
|
|
$
|
852.8
|
|
Long-term
|
|
|
282.6
|
|
|
226.5
|
|
|
228.1
|
|
|
188.4
|
|
Total
|
|
$
|
1,084.0
|
|
$
|
1,132.9
|
|
$
|
898.2
|
|
$
|
1,041.2
|
|
Assets
and
liabilities from risk management activities are classified as current or
long-term based upon the maturities of the underlying contracts.
Utility
Segments
The
derivatives
listed in the above table as "Commodity contracts" include a limited number
of
electric purchase contracts at WPSC as well as financial derivative contracts
(NYMEX futures) used to mitigate the market price volatility of natural gas
used
by WPSC for the generation of electricity. The electric utility segment also
uses financial instruments to manage transmission congestion costs, which
are
shown in the above table as "Financial transmission rights." Derivative
instruments at the electric utility segment are entered into in accordance
with
the terms of the risk management policy and plan approved by the PSCW. Changes
in the fair value of derivative instruments are recognized as regulatory
assets
or liabilities as our regulators have allowed deferral of the mark-to-market
effects of derivative instruments at the utilities. Thus, management believes
any gains or losses resulting from the eventual 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 and electric energy purchase and sale
activities and foreign currency contracts used to manage foreign currency
exposure related to ESI's Canadian operations. In addition, ESI 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 result in a phase-out of Section 29/45K federal tax credits that can
be
recognized from ESI's investment in a synthetic fuel production facility
for
2006 and 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 three months ended June 30, 2006, and June 30,
2005. Fair value hedge ineffectiveness recorded in nonregulated revenue on
the
Condensed Consolidated Statements of Income was a pre-tax gain of
$2.6 million for the six months ended June 30, 2006, and was not
significant for the six months ended June 30, 2005. At June 30, 2006,
and 2005, pre-tax mark-to-market losses of $4.5 million and
$5.7 million, respectively, related to changes in the difference between
the spot and forward prices of natural gas were excluded from the assessment
of
hedge effectiveness. These losses were reported directly in earnings in the
current and prior periods and will reverse when all of the related natural
gas
is withdrawn from storage.
Commodity
contracts
that are designated as cash flow hedges extend through June 2011 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 taxes. Cash flow hedge ineffectiveness recorded
in
nonregulated revenue on the Condensed Consolidated Statements of Income related
to commodity contracts was a pre-tax gain of $2.8 million for the three
months ended June 30, 2006, and was not significant for the three months
ended June 30, 2005. Cash flow hedge ineffectiveness recorded in
nonregulated revenue on the Condensed Consolidated Statements of Income related
to commodity contracts was a pre-tax gain of $4.1 million for the six
months ended June 30, 2006, and was not significant for the six months
ended June 30, 2005. 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 or if it is probable that the hedged transaction
will not occur. During the three and six months ended June 30, 2006 and
2005, the amounts reclassified from other comprehensive income into earnings
as
a result of the discontinuance of cash flow hedge accounting for certain
hedge
transactions related to commodity contracts were not significant. In the
next
12 months, subject to changes in market prices of natural gas and
electricity, we expect that an after-tax gain of $14.9 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
that
are being hedged.
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
variable rate obligation. An interest rate swap used to fix the interest
rate on
the Sunbury non-recourse debt was previously designated as a cash flow hedge.
As
a result of the debt restructuring, the hedged transaction no longer occurred.
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 three and six months
ended June 30, 2006 and 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 a $0.9 million pre-tax reduction to interest
expense related to these swaps, assuming interest rates comparable to those
at
June 30, 2006. We did not exclude any components of the derivative
instruments' change in fair value from the assessment of hedge
effectiveness.
In
the first quarter of 2006, WPS Resources entered into a forward-starting
interest rate swap with a ten-year term beginning in August 2006 with a notional
amount of $200 million to hedge a portion of the interest rate risk
associated with the planned issuance of fixed-rate, long-term debt securities
in
2006. The swap protects against the risk of changes in future interest payments
resulting from changes in benchmark rates between the date of hedge inception
and the date of the debt issuance. This derivative instrument qualifies for
cash
flow hedge treatment and is considered highly effective in hedging the benchmark
interest rate risk on the forecasted debt issuance. As a result, changes
in the
fair value of the swap are recorded through other comprehensive income, net
of
taxes. The swap will be terminated when the related debt is issued, and amounts
included in accumulated other comprehensive income will be reclassified into
earnings as the related interest expense on the debt accrues.
NOTE
4--SUNBURY
In
July, 2006, ESI completed the sale of Sunbury Generation, LLC to Corona
Power, LLC. Sunbury Generation's primary asset was the Sunbury generation
plant
located in Pennsylvania. The gross proceeds received in the transaction were
$34.6 million, subject to various working capital and other post-closing
adjustments, and the pre-tax gain to be recorded in the third quarter is
expected to be approximately $19 million. In conjunction with the sale, the
company also anticipates generating approximately $14 million in cash tax
benefits that will be realized within the next few years, with the timing
subject to the use of alternative minimum tax credits. This facility sold
power
on a wholesale basis when market conditions were economically favorable.
ESI has
been evaluating Sunbury's future since 2004, after an agreement to sell Sunbury
to Duquesne Power, L.P. was terminated. The sale of Sunbury allows ESI to
better
focus on its existing competitive energy business, while continuing to evaluate
other strategic opportunities to add to and optimize the value of its generation
fleet.
At
June 30, 2006, and December 31, 2005, the assets and liabilities
associated with Sunbury that were transferred to Corona Power, LLC have been
classified as held for sale in accordance with SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No.
144
requires that a long-lived asset classified as held for sale be measured
at the
lower of its carrying amounts or fair value, less costs to sell, and cease
being
depreciated. No adjustments to write down the Sunbury assets were required
during the six months ended June 30, 2006. The major classes of assets and
liabilities held for sale are as follows:
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Inventories
|
|
$
|
13.3
|
|
$
|
6.6
|
|
Other
current
assets
|
|
|
5.3
|
|
|
5.0
|
|
Property,
plant, and equipment, net
|
|
|
2.4
|
|
|
1.3
|
|
Other
assets
(includes emission credits)
|
|
|
1.9
|
|
|
1.9
|
|
Assets
held
for sale
|
|
$
|
22.9
|
|
$
|
14.8
|
|
|
|
|
|
|
|
|
|
Other
current
liabilities
|
|
$
|
1.0
|
|
$
|
1.0
|
|
Asset
retirement obligations
|
|
|
5.7
|
|
|
5.6
|
|
Liabilities
held for sale
|
|
$
|
6.7
|
|
$
|
6.6
|
|
A
summary of the components of discontinued operations recorded in the Condensed
Consolidated Statements of Income for the three months ended June 30 was as
follows:
(Millions)
|
|
2006
|
|
2005
|
|
Nonregulated
revenue
|
|
$
|
22.5
|
|
$
|
13.0
|
|
Operating
expenses
|
|
|
|
|
|
|
|
Nonregulated
cost of fuel, natural gas, and purchased power
|
|
|
(22.6
|
)
|
|
(8.1
|
)
|
Operating
and
maintenance expense
|
|
|
(8.8
|
)
|
|
(8.3
|
)
|
Depreciation
expense
|
|
|
(0.2
|
)
|
|
-
|
|
Gain
on sale
of emission allowances
|
|
|
-
|
|
|
85.9
|
|
Impairment
loss
|
|
|
-
|
|
|
(80.6
|
)
|
Interest
expense
|
|
|
-
|
|
|
(9.2
|
)
|
Loss
before
taxes
|
|
|
(9.1
|
)
|
|
(7.3
|
)
|
Income
tax
benefit
|
|
|
3.5
|
|
|
2.6
|
|
Discontinued
operations, net of tax
|
|
$
|
(5.6
|
)
|
$
|
(4.7
|
)
|
A
summary of the components of discontinued operations recorded in the Condensed
Consolidated Statements of Income for the six months ended June 30 was as
follows:
(Millions)
|
|
2006
|
|
2005
|
|
Nonregulated
revenue
|
|
$
|
59.4
|
|
$
|
37.8
|
|
Operating
expenses
|
|
|
|
|
|
|
|
Nonregulated
cost of fuel, natural gas, and purchased power
|
|
|
(50.3
|
)
|
|
(19.8
|
)
|
Operating
and
maintenance expense
|
|
|
(15.6
|
)
|
|
(14.3
|
)
|
Depreciation
expense
|
|
|
(0.3
|
)
|
|
-
|
|
(Loss)
gain
on sale of emission allowances
|
|
|
(0.4
|
)
|
|
86.8
|
|
Impairment
loss
|
|
|
-
|
|
|
(80.6
|
)
|
Taxes
other
than income
|
|
|
(0.1
|
)
|
|
(0.1
|
)
|
Interest
income (expense)
|
|
|
0.1
|
|
|
(10.6
|
)
|
Loss
before
taxes
|
|
|
(7.2
|
)
|
|
(0.8
|
)
|
Income
tax
benefit
|
|
|
2.8
|
|
|
0.3
|
|
Discontinued
operations, net of tax
|
|
$
|
(4.4
|
)
|
$
|
(0.5
|
)
|
Interest
income
recorded for the quarter and six months ended June 30, 2006 was not
significant. For the quarter and six months ended June 30, 2005, interest
expense of $9.1 million was recognized related to the termination of an
interest rate swap pertaining to Sunbury's non-recourse debt obligation in
addition to the recognition of interest expense on the non-recourse debt
prior
to the restructuring of this debt in the second quarter of 2005. The
restructuring of the Sunbury debt to a WPS Resources obligation in
June 2005 triggered the recognition of interest expense equivalent to the
mark-to-market value of the swap at the date of restructuring.
NOTE
5--ACQUISITIONS AND SALES OF ASSETS
Proposed
Merger with Peoples Energy Corporation
On
July 10, 2006, WPS Resources and Peoples Energy Corporation announced
they had entered into a definitive merger agreement. Upon consummation of
the
transaction set forth in the merger agreement, each common share of Peoples
Energy will be converted into 0.825 shares of WPS Resources' common stock
and will result in WPS Resources' shareholders owning approximately 58
percent of the combined company, and Peoples Energy shareholders owning
approximately 42 percent. The transaction, which was unanimously approved
by
both companies' Boards of Directors, is subject to receipt of all necessary
regulatory approvals and certain shareholder approvals. The transaction is
conditioned upon approval by the shareholders of both companies, expiration
or
early termination of the applicable Hart-Scott-Rodino waiting period, and
the
approval of various state and federal regulatory authorities, including the
FERC
and the ICC. WPS Resources will also seek PSCW approval of an amendment to
its affiliated interest
agreement.
An
expedited regulatory approval will be requested from the ICC. If expedited
regulatory approval is granted, the transaction is expected to be completed
in
the first quarter of 2007.
Peoples
Energy is a
diversified energy company consisting of four primary business segments:
natural
gas distribution, oil and natural gas production, energy assets and energy
marketing. The regulated business of Peoples Energy delivers natural gas
to
about one million customers in the city of Chicago and 54 communities in
northeastern Illinois. The nonregulated business serves more than 25,000
customers and provides a portfolio of products to manage energy needs of
business, industrial and residential customers.
For
accounting
purposes, the merger will be accounted for under the purchase method of
accounting with WPS Resources treated as the acquirer. The combination of
the two companies will create a diversified regulated utility business that
will
serve about 1.6 million natural gas customers and over 450,000 electric
customers.
Sale
of
Kimball Storage Field
In
April 2006, ESI sold WPS ESI Gas Storage, LLC, which owns a natural
gas storage field located in the Kimball Township, St. Clair County, Michigan.
ESI utilized this facility primarily for structured wholesale natural gas
transactions as natural gas storage spreads presented arbitrage opportunities.
ESI was not actively marketing this facility for sale, but believed the price
being offered was above the value it would realize from continued ownership
of
the facility. Proceeds received in April from the sale of the Kimball
natural gas storage field, and other related assets were $19.9 million,
which resulted in a pre-tax gain of $9.0 million in the second quarter of
2006.
Sale
of
Guardian Pipeline
In
April 2006, WPS Investments, LLC, a subsidiary of WPS Resources,
completed the sale of its one-third interest in Guardian Pipeline, LLC
to Northern Border Partners, LP for $38.5 million. The transaction resulted
in the recognition of a pre-tax gain of $6.2 million in the second quarter
of 2006.
Purchase
of
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. (Aquila) to acquire
its
natural gas distribution operations in Michigan and Minnesota for approximately
$558 million, exclusive of direct costs of the acquisition. This purchase
price excluded adjustments for working capital balances, including accounts
receivable, unbilled revenue, inventory, and certain other current assets,
and
is subject to other closing and post-closing adjustments. WPS Resources did
not assume any indebtedness in the transactions.
Michigan
On
April 1, 2006, WPS Resources, through its wholly owned subsidiary MGUC,
completed the acquisition of the natural gas distribution operations in Michigan
from Aquila. The Michigan natural gas assets provide natural gas distribution
service in 147 cities and communities primarily throughout Otsego, Grand
Haven,
and Monroe counties. The assets 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
paid total consideration of $343.9 million for the Michigan natural gas
distribution operations, which included closing adjustments related primarily
to
purchased working capital, which are still subject to minor adjustments.
The
transaction was initially funded with commercial paper borrowings supported
by
the revolving credit agreement entered into with J. P. Morgan Chase Bank
and
Bank of America Securities LLC (see Note 7 "Short-Term
Debt
and Lines of Credit"
for more
information on the revolving credit agreements). Permanent financing for
the
acquisition is expected to include a combination of common equity, long-term
debt instruments, and possibly other hybrid securities. The transaction was
accounted for under the purchase method of accounting. The purchase price
($343.9 million) was allocated based on the estimated fair market value of
the assets acquired and
liabilities
assumed. The excess cost of the acquisition over the estimated fair value
of the
tangible net assets acquired was allocated to identifiable intangible assets
with the remainder then allocated to goodwill. The results of operations
are
included in the accompanying condensed consolidated financial statements
since
the date of acquisition. The fair values set forth below are preliminary
and are
subject to adjustment as additional information is obtained. When finalized,
adjustments to goodwill may also result. The following table shows the
preliminary allocation of the purchase price to the assets acquired and
liabilities assumed at the date of the acquisition. Valuation specialists
with
expertise in performing appraisals assisted in determining the fair value
of the
assets acquired and liabilities assumed.
(Millions)
|
|
|
|
Accounts
receivable, net
|
|
$
|
28.6
|
|
Accrued
unbilled revenues
|
|
|
15.6
|
|
Inventories
|
|
|
23.9
|
|
Other
current
assets
|
|
|
3.3
|
|
Property
plant and equipment, net
|
|
|
137.2
|
|
Regulatory
assets
|
|
|
25.2
|
|
Long-term
assets
|
|
|
|
|
Goodwill
|
|
|
152.8
|
|
Intangibles - trade name
|
|
|
5.2
|
|
Other
long-term assets
|
|
|
6.2
|
|
Total
Assets
|
|
|
398.0
|
|
|
|
|
|
|
Other
current
liabilities
|
|
|
(6.1
|
)
|
Regulatory
liabilities
|
|
|
(1.2
|
)
|
Environmental
remediation liabilities
|
|
|
(24.9
|
)
|
Pension
and
postretirement benefit obligations
|
|
|
(21.6
|
)
|
Other
long-term liabilities
|
|
|
(0.3
|
)
|
Total
Liabilities
|
|
|
(54.1
|
)
|
Net
assets
acquired
|
|
$
|
343.9
|
|
The
following table
provides supplemental pro forma results of operations for the six months
ended
June 30, 2006 and 2005 and for the three months ended June 30, 2005,
as if the acquisition of the Michigan natural gas distribution operations
from
Aquila had been completed at the beginning of 2006 and 2005 respectively.
Pro
forma results are presented for informational purposes only, assume commercial
paper was used to finance the transaction, and are not necessarily indicative
of
the actual results that would have resulted had the acquisition actually
occurred on January 1, 2006 and January 1, 2005.
(Millions)
|
|
Pro
Forma for
the Six
Months
Ended
June 30
|
|
Pro
Forma for
the Three Months Ended June 30
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
Net
revenue
|
|
$
|
3,581.8
|
|
$
|
2,903.8
|
|
$
|
1,346.9
|
|
Income
available for common shareholders
|
|
$
|
101.3
|
|
$
|
94.1
|
|
$
|
22.4
|
|
Basic
earnings per share
|
|
$
|
2.46
|
|
$
|
2.48
|
|
$
|
0.59
|
|
Diluted
earnings per share
|
|
$
|
2.45
|
|
$
|
2.46
|
|
$
|
0.58
|
|
Minnesota
On
July 1, 2006, WPS Resources, through its wholly owned subsidiary MERC,
completed the acquisition of the natural gas distribution operations in
Minnesota from Aquila. The Minnesota natural gas assets provide natural gas
distribution service in 165 cities and communities including Grand Rapids,
Pine
City, Rochester, and Dakota County. The assets operate under a cost of service
environment and are currently allowed an 11.7% return on equity on a 50%
equity
component of the regulatory capital structure.
WPS Resources
paid total cash consideration of $333.3 million for the Minnesota natural
gas distribution operations, which includes estimated closing adjustments
of
$45.3 million related primarily to purchased working capital. The
transaction was initially funded with commercial paper borrowings supported
by
the revolving credit agreements entered into with J. P. Morgan Chase Bank
and
Bank of America Securities LLC (see Note 7 "Short-Term
Debt
and Lines of Credit"
for more
information on the revolving credit agreements). WPS Resources placed
$333.3 million of cash into escrow for the acquisition at
June 30, 2006. Cash held in escrow is recorded as "restricted cash for
acquisition" within long-term assets on the WPS Resources Condensed
Consolidated Balance Sheets. Aquila took legal possession of the escrowed
funds
on July 1, 2006. Permanent financing for the acquisition is expected
to include a combination of common equity, long-term debt instruments, and
possibly other hybrid securities. The transaction will be accounted for under
the purchase method of accounting in the third quarter of 2006. The final
purchase price is still subject to post-closing adjustments.
NOTE
6--GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
recorded
by WPS Resources was $189.2 million at June 30, 2006, and
$36.8 million at December 31, 2005. At June 30, 2006,
$152.8 million of goodwill was related to the acquisition of the natural
gas distribution operations in Michigan, and $36.4 million was recorded in
WPSC's natural gas segment related to its 2001 acquisition of Wisconsin Fuel
and
Light. At December 31, 2005, goodwill consisted of $36.4 million
related to WPSC's natural gas utility business, with the remaining
$0.4 million related to ESI. Also in conjunction with the acquisition of
the natural gas distribution operations in Michigan, a $5.2 million
(preliminary) indefinite lived intangible asset was recorded at June 30,
2006, related to the MGUC trade name.
Goodwill
and
purchased intangible assets are included as a component of other assets within
the Condensed Consolidated Balance Sheets. Information in the tables below
relates to purchased identifiable intangible assets for the periods
indicated.
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Asset
Class
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Emission
allowances(1)
|
|
|
2.6
|
|
|
(0.2
|
)
|
|
2.4
|
|
$
|
39.3
|
|
$
|
(22.2
|
)
|
$
|
17.1
|
|
Customer
related
|
|
|
7.2
|
|
|
(3.3
|
)
|
|
3.9
|
|
|
10.2
|
|
|
(5.6
|
)
|
|
4.6
|
|
Other
|
|
|
3.7
|
|
|
(0.8
|
)
|
|
2.9
|
|
|
4.2
|
|
|
(0.9
|
)
|
|
3.3
|
|
Total
|
|
$
|
13.5
|
|
$
|
(4.3
|
)
|
$
|
9.2
|
|
$
|
53.7
|
|
$
|
(28.7
|
)
|
$
|
25.0
|
|
(1)Emission
allowances
have a weighted-average amortization period of one to six years.
Intangible
asset
amortization expense, in the aggregate, for the three months ended June 30,
2006 and 2005, was $0.5 million and $2.4 million, respectively.
Intangible asset amortization expense, in the aggregate, for the six months
ended June 30, 2006 and 2005, was $1.1 million and $3.0 million,
respectively. Most of the emission allowances on hand at December 31, 2005,
had
been purchased to operate the Sunbury plant prior to the sale of this facility,
which occurred in July 2006. These emission allowances were not included
as held
for sale at December 31, 2005, because they did not transfer to Corona Power,
LLC in the sale. ESI utilized the majority of the emission allowances it
had on
hand at December 31, 2005, to operate its Sunbury plant prior to the sale.
The
amortization of these emission allowances is included as a component of
discontinued operations, as a component of nonregulated cost of fuel, natural
gas, and purchased power. See Note 4, "Sunbury,"
for more
information.
Amortization
expense for the next five fiscal years is estimated as follows:
Estimated
Future Amortization Expense (millions)
|
|
|
|
For
six
months ending December 31, 2006
|
|
$
|
0.8
|
|
For
year
ending December 31, 2007
|
|
|
1.3
|
|
For
year
ending December 31, 2008
|
|
|
1.0
|
|
For
year
ending December 31, 2009
|
|
|
0.8
|
|
For
year
ending December 31, 2010
|
|
|
0.6
|
|
NOTE
7--SHORT-TERM DEBT AND LINES OF CREDIT
In
June 2006, WPS Resources entered into an unsecured $500 million
5-year credit agreement. This revolving credit facility replaced the
$300 million bridge credit facility discussed below and is in addition to
the previously existing credit line facility which also has a borrowing capacity
of $500 million, bringing WPS Resources' total borrowing capacity
under its general credit agreements to $1 billion. Both credit lines back
WPS Resources' commercial paper borrowing programs and letters of credit.
The first $500 million credit line was entered into in June 2005, and
is an unsecured 5-year credit agreement. In June 2005, WPSC also entered
into a
5-year credit facility for $115 million to replace its former 364-day
credit line facility for the same amount. This credit line is used to back
100%
of WPSC's commercial paper borrowing programs and letters of credit for WPSC.
As
of June 30, 2006, there was a total of $592.9 million and
$26.2 million available under WPS Resources' and WPSC's general credit
lines, respectively.
In
November 2005, WPS Resources entered into two unsecured revolving
credit agreements of $557.5 million and $300 million with J. P.
Morgan Chase Bank and Bank of America Securities LLC. As discussed above,
the
$500 million 5-year credit agreement entered into in June 2006
replaced the $300 million bridge credit facility. The $557.5 million
credit facility is a bridge facility intended to backup commercial paper
borrowings related to the purchase of the natural gas distribution operations
in
Michigan and Minnesota. The capacity under the $557.5 million bridge facility
is
reduced by the amount of proceeds from any long-term financing
WPS Resources completes, with the exception of proceeds received from the
November 2005 equity offering. On May 10, 2006, as a result of
WPS Resources' physical settlement of its forward equity agreement (and
issuing 2.7 million shares of common stock upon settlement), the
$557.5 million facility was reduced to $417.9 million. This credit
agreement will be further reduced as permanent or replacement financing is
secured. The $417.9 million credit agreement matures on
September 5, 2007, and has representations and covenants that are
similar to those in WPS Resources' general credit facilities. On
March 31, 2006, in order to meet short-term financing requirements related
to the acquisition of the natural gas distribution operations in Michigan,
WPS Resources issued $269.5 million of commercial paper supported by
the $417.9 million bridge credit facility. On July 1, 2006, in order
to meet short-term financing requirements related to the acquisition of the
natural gas distribution operations in Minnesota, WPS Resources issued
commercial paper in the amount of $333.3 million, partially supported by
the $417.9 million bridge facility, with the remaining commercial paper
supported by the general credit facilities discussed above. See Note 5,
"Acquisitions
and Sales of Assets,"
for more
information related to the acquisitions of the natural gas distribution
operations in Michigan and Minnesota.
The
increase in
short-term notes payable outstanding relates to a $150 million credit
agreement that ESI entered into in April 2006, to finance its margin
requirements related to natural gas and electric contracts traded on the
NYMEX
and the ICE, as well as the cost of natural gas in storage and for general
corporate purposes. At June 30, 2006, ESI maximized its borrowing
capabilities under this agreement.
The
information in
the table below relates to WPS Resources' short-term debt and lines of
credit as of the time periods indicated.
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Commercial
paper outstanding
|
|
$
|
834.2
|
|
$
|
254.8
|
|
Average
discount rate on outstanding commercial paper
|
|
|
5.45
|
%
|
|
4.54
|
%
|
Short-term
notes payable outstanding
|
|
$
|
168.6
|
|
$
|
10.0
|
|
Average
interest rate on short-term notes payable
|
|
|
5.59
|
%
|
|
4.32
|
%
|
Available
(unused) lines of credit
|
|
$
|
619.1
|
|
$
|
249.1
|
|
The
commercial
paper at June 30 had varying maturity dates ranging from July 5 through
August 31, 2006.
The
information in
the table below relates to WPSC's short-term debt and lines of credit as
of the
time periods indicated.
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Commercial
paper outstanding
|
|
$
|
85.0
|
|
$
|
75.0
|
|
Average
discount rate on outstanding commercial paper
|
|
|
5.48
|
%
|
|
4.54
|
%
|
Short-term
notes payable outstanding
|
|
$
|
10.0
|
|
$
|
10.0
|
|
Average
interest rate on short-term notes payable
|
|
|
5.15
|
%
|
|
4.32
|
%
|
Available
(unused) lines of credit
|
|
$
|
26.2
|
|
$
|
36.2
|
|
The
commercial
paper at June 30 had varying maturity dates ranging from July 5 through
July 11, 2006.
NOTE
8--LONG-TERM DEBT
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
14.4
|
|
|
14.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
65.6
|
|
Term
loans -
non-recourse, collateralized by nonregulated assets
|
|
15.2
|
|
|
16.4
|
|
Tax
exempt
bonds
|
|
27.0
|
|
|
27.0
|
|
Senior
secured note
|
|
2.2
|
|
|
2.4
|
|
Total
|
|
871.5
|
|
|
872.9
|
|
Unamortized
discount and premium on bonds and debt
|
|
(1.6
|
)
|
|
(1.8
|
)
|
Total
debt
|
|
869.9
|
|
|
871.1
|
|
Less
current
portion
|
|
(4.2
|
)
|
|
(4.0
|
)
|
Total
long-term debt
|
$
|
865.7
|
|
$
|
867.1
|
|
NOTE
9--ASSET RETIREMENT OBLIGATIONS
Under
the
provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations,"
and Interpretation No. 47, "Accounting for Conditional Asset Retirement
Obligations," WPS Resources has recorded liabilities for legal obligations
associated with the retirement of tangible long-lived assets. The utility
segments identified asset retirement obligations primarily related to asbestos
abatement at certain generation facilities, office buildings, and service
centers; disposal of PCB-contaminated transformers; and closure of fly-ash
landfills at certain generation facilities. Additional asset retirement
obligations related to asbestos abatement were recorded in connection with
the
acquisition of the natural gas distribution operations in Michigan. In
accordance with SFAS No. 71, the utilities establish regulatory assets and
liabilities to record the differences between ongoing expense recognition
under
SFAS No. 143 and Interpretation No. 47, and the rate-making practices
for retirement costs authorized by the PSCW and MPSC. Asset retirement
obligations identified at ESI relate to asbestos abatement at certain generation
facilities as well as closure of an ash basin located at Sunbury. The asset
retirement obligations related to Sunbury are recorded as liabilities held
for
sale in the Condensed Consolidated Balance Sheets of WPS Resources. See
Note 4, "Sunbury,"
for more
information. All other asset retirement obligations are recorded as other
long-term liabilities in the Condensed Consolidated Balance Sheets of
WPS Resources and WPSC.
The
following table
shows all changes to the asset retirement obligation liabilities of
WPS Resources.
(Millions)
|
|
Utilities
|
|
ESI
|
|
Total
|
|
Asset
retirement obligations at December 31, 2005
|
|
$
|
8.6
|
|
$
|
6.3
|
|
$
|
14.9
|
|
Asset
retirement obligations from acquisition of natural gas operations
in
Michigan
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
Accretion
expense
|
|
|
0.2
|
|
|
0.2
|
|
|
0.4
|
|
Asset
retirement obligations at June 30, 2006
|
|
|
8.9
|
|
|
6.5
|
|
|
15.4
|
|
Asset
retirement obligations classified as held for
sale
|
|
|
-
|
|
|
5.7
|
|
|
5.7
|
|
Asset
retirement obligations at June 30, 2006,
excluding
those classified as held for sale
|
|
$
|
8.9
|
|
$
|
0.8
|
|
$
|
9.7
|
|
WPSC's
share of the
asset retirement obligations in the above table equaled $7.9 million at
June 30, 2006, and $7.7 million at December 31, 2005. Accretion
expense at WPSC for the six months ended June 30, 2006 was
$0.2 million.
NOTE
10--INCOME TAXES
The
effective tax
rate for the three and six months ended June 30, 2006 was 31.3% and 31.5%,
respectively. The effective tax rate for the three and six months ended June
30,
2005 was 20.3% and 20.6%, respectively. WPS Resources' and WPSC's provision
for income taxes were 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
June 30, 2006.
ESI
has
unconditional purchase obligations related to energy supply contracts that
total
$5.6 billion.
Substantially all of these obligations end by 2008, with obligations totaling
$549.3 million extending from 2009 through 2017. 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. Obligations
related to coal supply and transportation extend through 2016 and total
$491.9 million. Through 2016, WPSC has obligations totaling
$1.4 billion for either capacity or energy related to purchased power.
Also, there are natural gas supply and transportation contracts with total
estimated demand payments of $111.8 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.
UPPCO
has made
commitments for the purchase of commodities, mainly capacity or energy related
to purchased power, which total $32.8 million and extend through
2010.
MGUC
has
obligations related to natural gas contracts totaling $51.5 million,
substantially all of which end by 2009.
WPS Resources
also has commitments in the form of purchase orders issued to various vendors.
At June 30, 2006, these purchase orders totaled $478.1 million and
$411.7 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.
Environmental
EPA
Section
114 Request
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 provided by WPSC and Wisconsin
Power and Light Company, 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. WPSC has no notice of such a claim based on the information submitted
to
the EPA.
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 generation 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 $30 million. 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/or
|
·
|
pay
a fine
and conduct a supplemental environmental project in order to resolve
any
such claim.
|
Pulliam
Air
Permit Violation Lawsuit
The
Sierra Club and
Clean Wisconsin filed a complaint in the Eastern District of Wisconsin on
October 19, 2005. The lawsuit was filed pursuant to the citizen suit
provisions of the Clean Air Act. The complaint references opacity exceedances
reported by the Pulliam facility located in Green Bay, Wisconsin, from 1999
through the first quarter of 2005. The complaint also alleges monitoring
violations from 1999 through 2004, 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 one of the combustion turbines. The
lawsuit seeks penalties, injunctive relief, and costs of litigation. WPSC
filed
an answer to the complaint on March 6, 2006, asserting a number of
affirmative defenses. The Sierra Club and Clean Wisconsin have stated a
willingness to discuss the alleged violations and the parties continue to
be
engaged in settlement negotiations.
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, the WDNR
granted the petition and forwarded the matter to the Division of Hearings
and
Appeals. In its petition, the 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. Certain issues were decided on summary judgment in favor
of WPSC
with respect to certain Sierra Club claims 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. In February 2006, the Administrative Law Judge affirmed the
Weston 4 air permit with modifications to the emission limits for sulfur
dioxide and nitrogen oxide from the coal-fired boiler and particulate from
the
cooling tower. The modifications set limits that are more stringent than
those
set by the WDNR. The Sierra Club and WPSC filed petitions for judicial review
of
the Administrative Law Judge's decision with the circuit court, both of which
are pending. WPSC's petition is limited to a review of the decision related
to
sulfur dioxide limitations. The filing of the petitions did not stay the
Administrative Law Judge's decision. WPSC expects that the WDNR intends to
revise the air permit consistent with that decision unless otherwise directed
by
the court.
Weston
4
Discovery Complaint
On
December 16, 2005, the Sierra Club filed a complaint with the PSCW alleging
that WPSC failed to respond accurately and completely to a PSCW staff request
for information about air pollution control technology available for the
Weston
4 electric generation facility, the construction of which was authorized
by the
PSCW in October 2004. Following an informal investigation, the PSCW
determined that, although the alleged failure to provide the information
did not
adversely affect the outcome of the case, WPSC may not have fully complied
with the PSCW's procedural rules. Based on this determination, the PSCW referred
the matter to the Wisconsin Attorney General for investigation and potential
enforcement action. WPSC does not believe that it violated the PSCW's procedural
rules. Moreover, both the PSCW and the WDNR have determined that any error
by
WPSC would not have impacted the outcome of the cases involved. Nonetheless,
the
referral to the Attorney General could result in enforcement action against
WPSC. Any such enforcement action may result in a civil forfeiture or fine.
At
this time, WPSC believes that its exposure to fines or penalties related
to this
noncompliance will not have a material impact on its financial results.
Weston
Site
Operating 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 (CO) 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. In response to the NOV, a compliance plan
was
submitted to the WDNR. Subsequently, stack testing was performed, which
indicated continuing exceedances of the particulate limits from the coal
handling equipment. On January 19, 2006, WPSC received from the WDNR a Notice
of
Noncompliance (NON) seeking further information about the alleged non-compliance
event. WPSC provided a response to the WDNR and is in the process of seeking
to
have the permit revised. On February 20, 2006, the WDNR issued an NOV which
incorporated most of the alleged noncompliance events described above (the
alleged exceedances of the CO limit was not included) and added issues relating
to opacity monitoring and the operation of a particulate source for three
days
without a functioning baghouse. 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. In addition, citizen groups
may seek to initiate enforcement prior to the filing of any lawsuit by the
Wisconsin Attorney General's Office or may seek to intervene in the Title V
operating permit revision process. WPSC is seeking to amend the applicable
permit limits and is taking corrective action. At this time, WPSC believes
that
its exposure to fines or penalties related to this noncompliance will not
have a
material impact on its 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
future rate cases.
In
March 2005, the EPA finalized the mercury "maximum achievable control
technology" standards and an alternative mercury "cap and trade" program,
Clean
Air Mercury Rule, modeled on the Clear Skies legislation initiative. The
EPA
also finalized the Clean Air Interstate Rule (formerly known as the Interstate
Air Quality Rule), which will reduce sulfur dioxide and nitrogen oxide emissions
from utility boilers located in 29 states, including Wisconsin, Michigan,
Pennsylvania, and New York.
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 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 and does
not anticipate incurring costs beyond those to comply with the Wisconsin
rule.
ESI's
current
analysis indicates that additional emission control equipment on its existing
units may be required. ESI estimates the capital costs to be approximately
$1 million to achieve a 70% reduction, excluding Sunbury.
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 ESI'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 $268 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.
ESI
is evaluating
the compliance options for the Clean Air Interstate Rule. Additional nitrogen
oxide controls on some of ESI's facilities may be necessary, and would cost
approximately $3 million, excluding Sunbury. ESI 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 ESI are located in an ozone transport region.
As
a result, these generation facilities are subject to additional restrictions
on
emissions of nitrogen oxide and sulfur dioxide. In future years, ESI expects
to
purchase sulfur dioxide and nitrogen oxide emission allowances at market
rates,
as needed, to meet requirements for its generation facilities.
Spent
Nuclear Fuel Disposal
The
federal
government is responsible for the disposal or permanent storage of spent
nuclear
fuel. The DOE is currently preparing an application to license a permanent
spent
nuclear fuel storage facility in the Yucca Mountain area of Nevada. Spent
nuclear fuel is currently being stored at the Kewaunee Nuclear Power Plant
formerly owned by WPSC.
The
United States
government through the DOE was under contract with WPSC for the pick up and
long-term storage of Kewaunee's spent nuclear fuel. Because the DOE has failed
to begin scheduled pickup of the spent nuclear fuel, WPSC incurred costs
for the
storage of the spent nuclear fuel. WPSC is a participant in a suit filed
against
the federal government for breach of contract and failure to pick up and
store
the spent nuclear fuel. The case was filed on January 22, 2004, in the United
States Court of Federal Claims. The case has been temporarily stayed until
December 31, 2006.
In
July 2005, WPSC sold Kewaunee to a subsidiary of Dominion Resources, Inc.
Pursuant to the terms of the sale, Dominion has the right to pursue the spent
nuclear fuel claim and WPSC will retain the contractual right to an equitable
share of any future settlement or verdict. The total amount of damages sought
is
unknown at this time.
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,
Menominee, and two Sheboygan sites in Wisconsin is completed. Groundwater
treatment and monitoring at these sites will continue into the future. Cleanup
of the land portion of three 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. The additional
work
at the sites remains to be scheduled.
In
May 2006, WPSC transferred six 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. A schedule has been agreed to under which onsite
investigative work will commence at two of the sites in 2007. WPSC estimated
the
future undiscounted investigation and cleanup costs as of June 30, 2006, to
be approximately $65 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.
MGUC,
which
acquired retail natural gas operations in Michigan from Aquila in the second
quarter of 2006, is responsible for the environmental impacts at 11 manufactured
gas plant sites. Removal of the most contaminated soil has been completed
at
seven sites. Future investigations are needed at many of the sites to evaluate
on-site, off-site, and sediment impacts.
MGUC
has estimated
future investigation and remediation costs of approximately $25 million.
The MPSC has historically authorized recovery of these costs. An environmental
liability and related regulatory asset were recorded at the date of acquisition
to reflect the expected investigation and clean-up costs relating to these
sites
and the expected recovery of these costs in future rates.
As
these 11 sites are integrated into the corporate gas plant site management
program, cost estimates may change. We will also evaluate the feasibility
of transferring the MGUC sites into the EPA Superfund Alternatives
Program.
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 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. This 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: Wisconsin
Electric Power Company, 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, ATC, and various land
and
home owners 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.
In
May 2005, 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.).
UPPCO has reached a confidential settlement with Wisconsin Electric Power
Company resolving Wisconsin Electric Power Company's claims. The settlement
payment has been reimbursed by WPS Resource's insurer and, therefore, did
not have a material impact on the Condensed Consolidated Financial Statements.
WPS Resources has also settled several small claims with various landowners
that are also covered by insurance. WPS Resources is defending the
remaining lawsuits filed against it and is seeking resolution of all claims
and
litigations where possible. A trial date in September 2007 has been set for
the remaining cases.
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.
UPPCO
has announced
its decision to restore Silver Lake as a reservoir for power generation pending
approval of an economically feasible design by the FERC. The FERC has required
that a board of consultants evaluate and oversee the design approval process.
UPPCO is developing a timeline for the project, provided the FERC approves
an
economically feasible design. Once work is done, Silver Lake is expected
to take
approximately two years to refill, based upon natural
precipitation.
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
$1.3 million and an associated regulatory asset of $1.3 million were
recorded at June 30, 2006, for estimated future expenditures associated
with remediation of the site. In addition, 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 year will be $1.8 million. UPPCO has recorded
$0.3 million of this amount as its share of the liability as of
June 30, 2006.
There
is increasing
concern over the issue of climate change and the effect of greenhouse gas
emissions. WPS Resources is evaluating both the technical and cost
implications which may result from a future greenhouse gas regulatory
program. This evaluation indicates that it is probable that any regulatory
program that caps emissions or imposes a carbon tax will increase costs for
WPS Resources and its customers. At this time, there is no commercially
available technology for removing carbon dioxide from a pulverized coal-fired
plant, but significant research is in progress. Efforts are underway within
the
utility industry to develop cleaner ways to burn coal. The use of alternate
fuels is also being explored by the industry, but there are many costs and
availability issues. Based on the complexity and uncertainty of the climate
issues, a risk exists that future carbon regulation will increase the cost
of
electricity produced at coal-fired generation units. However, we believe
the
capital expenditures we are making at our generation units are appropriate
under
any reasonable mandatory greenhouse gas program. WPS Resources will
continue to monitor and manage potential risks and opportunities associated
with
future greenhouse gas regulatory actions.
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,
was 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 dismissed on
June 21, 2005, when the trial judge granted WPSC's motion for a
directed
verdict.
The Seidl
plaintiffs appealed that dismissal. On July 18, 2006, the Court of Appeals
affirmed the trial judge's dismissal of the plaintiffs' case.
On
February 15, 2005, the Court of Appeals affirmed the jury verdict in
Allen
v.
WPSC,
which awarded the
plaintiff $0.8 million for economic damages and $1 million for
nuisance. All appeals have been exhausted and the judgment has been paid
to the
plaintiff, but the plaintiff is still seeking an injunction. The injunction
issues are scheduled to be tried to a judge, not a jury, in September 2006.
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 plaintiff's land. Accordingly, WPSC does
not
believe there is any basis for issuing an injunction, and intends to contest
the
plaintiff's claim. If the judge were to find an injunction was warranted,
WPSC
could be ordered to modify its electric distribution system. The plaintiff
would
then also assert a claim for monetary damages for the period from
June, 2003 to date.
Three
cases,
Theuerkauf
v.
WPSC,
Wojciehowski
Brothers Farms v. WPSC,
and Schmoker
v.
WPSC
were filed in the
fourth quarter of 2005. The Theuerkauf
case was brought
by Michigan farmers and was in federal court in Green Bay, but has recently
settled for an amount within the self-insured retention. The Wojciehowski
case was brought
in Wisconsin in Marinette County. It is currently in discovery and WPSC is
vigorously defending the case. The Schmoker
case was brought
in Wisconsin state court in Winnebago County. The parties are currently engaged
in settlement discussions.
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. However, 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. Thus,
despite the fact that WPSC believes it abides by the applicable PSCW
requirements, it is not immune from tort suits such as these under Wisconsin
law.
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 pending actions will not be material.
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 and subsequently transferred 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.
The
Certificate of
Public Convenience and Necessity and other permits needed for construction
have
been received and are 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 Douglas County Board approved that agreement. Accordingly, the
lawsuit
against Douglas County to force it to provide easements for the project has
been
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 ATC in exchange for the project funding.
Under its agreement, WPS Resources invested $22.4 million in ATC
during the six months ended June 30, 2006, bringing
WPS Resources'
investment
in ATC
related to the project to approximately $109 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. Allete exercised its option to
fund
a portion of the Wausau to Duluth transmission line. WPSC and Allete agreed
that
Allete will fund up to $60 million of the future capital calls for the
line. Considering this, for the period January 2006 through the anticipated
completion of the line in 2008, WPS Resources expects to fund up to
approximately $61 million for its portion of the Wausau to Duluth
transmission line.
Beaver
Falls
ESI'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. Inclusive of estimated insurance recoveries, ESI estimates
at
this time that it will cost approximately $5 million to repair the turbine
and replace the damaged blades. In addition, ESI continues to attempt to
renegotiate certain restrictive terms of an existing steam off-take agreement,
the outcome of which will significantly impact its ability to recover costs.
During the second quarter of 2006, natural gas prices decreased, and electric
prices and market volatility increased, which caused the value of the plant
to
go up. The carrying value of the Beaver Falls generation facility at
June 30, 2006, is $17.6 million. Although we have not finalized our
decision to repair the plant, it is probable that required repairs will be
made
due to improved economics of generation in New York.
Revenue
Sufficiency Guarantee Charges
On
April 25, 2006, the FERC issued an order regarding MISO's "Revenue Sufficiency
Guarantee" charges (RSG charges). MISO's business practice manuals and other
instructions to market participants have stated, since the implementation
of
market operations on April 1, 2005, that RSG charges will not be imposed
on
offers to supply power not supported by actual generation (also known as
virtual
supply offers). However, some market participants raised questions about
the
language of MISO's tariff concerning that issue and in October 2005, MISO
submitted to the FERC proposed tariff revisions clarifying its tariff to
reflect
its business practices with respect to RSG charges, and filed corrected tariff
sheets exempting virtual supply from RSG charges. In its April 2006 decision,
the FERC interpreted MISO's tariff to require that virtual supply offers
must be
included in the calculation of the RSG charges and that to the extent that
MISO
did not charge virtual supply offers for RSG charges, it violated the terms
of
its tariff. The FERC order then proceeded to require MISO to recalculate
the RSG
charges back to April 1, 2005, and to make refunds to customers, with
interest, reflecting the recalculated charges. In order to make such refunds,
it
is likely that MISO will attempt to impose retroactively RSG charges on those
who submitted virtual supply offers during the recalculation period. ESI
and our
electric utility segment made virtual supply offers in MISO during this period
on which no RSG charges were imposed, and thus may be subject to a claim
for
refunds from MISO (which claim will be contested). The electric utility segment
will be eligible for the refund discussed above, which is expected to more
than
offset any charges that will be imposed on the electric utility segment.
ESI,
however, is not eligible for any offsetting refunds. The FERC's April 2006
order
has been challenged by MISO and other parties, including WPS Resources, and
the
eventual outcome of these proceedings is unclear. As of the date of this
report,
we do not believe this issue will have a material impact on WPS Resources’
Consolidated Financial Statements.
Synthetic
Fuel Production Facility
Background
We
have significantly reduced our consolidated federal income tax liability
through
tax credits available to us under Section 29/45K of the Internal Revenue
Code
for the production and sale of solid synthetic fuel produced from coal. These
tax credits are scheduled to expire at the end of 2007 and are provided as
an
incentive
for
taxpayers to produce fuel 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 the fuel. Therefore,
the
tax credits in a given year are subject to phase-out if the annual average
reference price of oil within that year exceeds a minimum threshold price
set by
the Internal Revenue Service (IRS) and are eliminated entirely if the average
annual reference price increases beyond a maximum threshold price set by
the
IRS. The reference price of a barrel of oil is an estimate of the annual
average
wellhead price per barrel for domestic crude oil, which has in recent history
been approximately $6 below the NYMEX price of a barrel of 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.
Section
29/45K Federal Tax Credits Related to Our Ownership Interest in a Synfuel
Facility
Numerous
events
have increased domestic crude oil prices, including concerns about terrorism
and
foreign relations, storm-related supply disruptions, and worldwide demand.
Therefore, in order to mitigate exposure to the risk of an increase in oil
prices that could reduce the amount of Section 29/45K federal tax credits
that
could be recognized, ESI entered into a series of derivative (option) contracts,
beginning in the first quarter of 2005, covering a specified number of barrels
of oil. If no phase-out were to occur in 2006, we would expect to recognize
approximately $26 million of Section 29/45K federal tax credits from our
ownership interest in a synthetic fuel production facility. Based upon 2006
actual year-to-date and forward oil prices, we are anticipating significant
phase-outs of 2006 and 2007 Section 29/45K federal tax credits. However,
we
cannot predict with certainty the future price of a barrel of oil and,
therefore, have no way of knowing what portion of our 2006 and 2007 tax credits
will ultimately be phased out. ESI estimates that 2006 Section 29/45K
federal tax credits will begin phasing out if the annual average NYMEX price
of
a barrel of oil reaches approximately $60, with a total phase-out if the
annual
average NYMEX price of a barrel of oil reaches approximately $74. At
June 30, 2006, based upon estimated annual average oil prices, we
anticipate that approximately 76% of the 2006 tax credits that otherwise
would
be available from the production and sale of synthetic fuel would be phased-out.
For the year ending December 31, 2006, including the projected tax credit
phase-out, we expect to recognize the benefit of Section 29/45K federal tax
credits totaling approximately $7 million from our ownership interest in a
synthetic fuel production facility. However, the actual amount of tax credits
recognized in 2006 could differ substantially from our June 30, 2006
estimate, based upon actual average annual oil prices.
ESI
has derivative
(option) contracts that mitigate substantially all of the Section 29/45K
tax
credit exposure in 2006 and approximately 40% of the exposure in 2007. The
derivative contracts involve purchased and written options that provide for
net
cash settlement at expiration based on the annual average NYMEX trading price
of
oil in relation to the strike price of each option. Net premiums paid to
date
for options to mitigate exposure to Section 29/45K federal tax credit phase-outs
in 2006 and 2007 related to ESI's ownership interest in a synthetic fuel
production facility totaled $15.7 million ($12.4 million for 2006
options and $3.3 million for 2007 options), all of which are recorded as
risk management assets and liabilities on the balance sheet. Essentially,
ESI
paid $12.4 million for options ($7.4 million after-tax) to protect the
value of approximately $26 million of tax credits in 2006 and
$3.3 million for options ($2.0 million after-tax) to protect the value
of approximately $10 million of tax credits in 2007. ESI has not hedged an
estimated $16 million of 2007 tax credits. 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 as a component of nonregulated
revenue. This results in mark-to-market gains being recognized in earnings
in
different periods, compared to any offsetting tax credit phase-outs. For
example, from the inception of ESI's Section 29/45K hedging strategy in the
first quarter of 2005 through June 30, 2006, total pre-tax mark-to-market
and realized gains recognized on 2006 oil options were $22.0 million, while
total pre-tax mark-to-market gains recognized on 2007 oil options were
$9.4 million. These pre-tax gains compared to a phase-out of approximately
$10 million of tax credits during the first six months of 2006 (no tax
credit phase-outs were recognized in 2005).
In
addition to exposure from federal tax credits, ESI has also historically
received royalties tied to the amount of synthetic fuel produced as well
as
variable payments from a counterparty related to ESI's 2002 sale of 30% of
its
interest in ECO Coal Pelletization #12. While variable payments are received
by
ESI quarterly, royalties are a function of annual synthetic fuel production
and
are generally not received until
later
in the year.
Because ESI's partners in the synthetic fuel facility have begun to curtail
their synthetic fuel production, it is unlikely ESI will recognize any royalty
income in 2006 or 2007, compared to $3.5 million of pre-tax royalty income
that was recognized in 2005. Income from variable payments received from
the
2002 sale (discussed above) is also likely to decrease. ESI expects to recognize
pre-tax income related to these variable payments of approximately
$2.6 million in 2006 and no income from the variable payments in 2007. In
comparison, ESI recognized pre-tax income of $3.7 million related to the
variable payments in 2005.
Additional
Synthetic Fuel Production Procured in 2006
ESI's
partner in
the synthetic fuel facility curtailed production during the second quarter
of
2006. In addition to the production ESI is entitled to based upon its ownership
interest in the synthetic fuel facility (discussed above), ESI also elected
to
take, and economically hedge the risk, associated with the additional production
its synthetic fuel partner curtailed. The following facts are pertinent to
understanding the impact this transaction had on results of operations for
the
six months ended June 30, 2006, and the impact for the remainder of
2006.
●
|
If
no
phase-out of Section 29/45k federal tax credits occurs in 2006,
the
additional production that was procured would result in the recognition
of
approximately $9 million of tax credits. This is in addition to the
$26 million of tax credits (disclosed above) that we would recognize
from production procured from our ownership interest in the synthetic
fuel
production facility.
|
●
|
For
the year
ending December 31, 2006, including the projected 76% tax credit
phase-out, we expect to recognize the benefit of Section 29/45K
federal
tax credits totaling approximately $2 million from the additional
production that was procured. This is in addition to the benefit
of
Section 29/45K federal tax credits totaling approximately $7 million
that we expect to recognize from our ownership interest in the
synthetic
fuel production facility, including the projected 76% tax credit
phase-out.
|
●
|
For
the
quarter and six months ended June 30, 2006, ESI's share of operating
losses from its investment in the synthetic fuel facility increased
approximately $4 million on a pre-tax basis, which was driven by the
additional synthetic fuel production procured.
|
●
|
Mark-to-market
gains on derivative instruments related to the economic hedging
strategies
for the additional production that was procured are included in
the table
below.
|
●
|
Absent
the
anticipated 76% tax credit phase-out, we estimate that an additional
income tax benefit of $7 million would have been recognized during
the six months ended June 30, 2006 from the procurement of the
additional production.
|
Impact
of
Synthetic Fuel Activities on Results of Operations
The
following table
shows the impact that ESI's investment in the synthetic fuel production facility
and procurement of additional tons, including derivative (option) contract
activity, had on the Condensed Consolidated Statements of Income for the
six
months ended June 30.
Amounts
are pre-tax, except tax credits (millions)
|
|
Income
(loss)
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
Provision
for
income taxes:
|
|
|
|
|
|
Section 29/45K federal tax credits recognized
|
|
$
|
7.6
|
|
$
|
18.6
|
|
|
|
|
|
|
|
|
|
Nonregulated
revenue:
|
|
|
|
|
|
|
|
Mark-to-market gains on 2005 oil options
|
|
|
-
|
|
|
0.2
|
|
Premium amortization on 2005 oil options
|
|
|
-
|
|
|
(1.5
|
)
|
Mark-to-market gains on 2006 oil options
|
|
|
17.7
|
|
|
3.1
|
|
Net
realized gains on 2006 oil options
|
|
|
2.0
|
|
|
-
|
|
Mark-to-market gains on 2007 oil options
|
|
|
5.0
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income:
|
|
|
|
|
|
|
|
Operating losses - synthetic fuel facility
|
|
|
(12.9
|
)
|
|
(8.4
|
)
|
Variable payments received
|
|
|
1.9
|
|
|
1.9
|
|
Royalty income recognized
|
|
|
-
|
|
|
-
|
|
Deferred gain recognized
|
|
|
1.1
|
|
|
1.1
|
|
Interest received on fixed note receivable
|
|
|
0.5
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
Minority
interest
|
|
|
2.4
|
|
|
2.4
|
|
NOTE
12--GUARANTEES
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.
Most
of 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 and measurement requirements of FASB
Interpretation No. 45, "Guarantors' Accounting and Disclosure Requirements
for Guarantees, including Indirect Guarantees of Indebtedness of Others."
Corporate
guarantees issued in the future under the Board authorized limits may or
may not be reflected on WPS Resources' Condensed Consolidated Balance
Sheet, depending on the nature of the guarantee.
At
June 30, 2006, and December 31, 2005, outstanding guarantees totaled
$1,479.4 million, and $1,310.6 million, respectively, as
follows:
WPS Resources'
Outstanding Guarantees
(Millions)
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Guarantees
of
subsidiary debt
|
|
$
|
178.4
|
|
$
|
27.2
|
|
Guarantees
supporting commodity transactions of subsidiaries
|
|
|
1,206.5
|
|
|
1,154.7
|
|
Standby
letters of credit
|
|
|
81.2
|
|
|
114.3
|
|
Surety
bonds
|
|
|
0.9
|
|
|
0.8
|
|
Other
guarantees
|
|
|
12.4
|
|
|
13.6
|
|
Total
guarantees
|
|
$
|
1,479.4
|
|
$
|
1,310.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WPS Resources'
Outstanding Guarantees
(Millions)
Commitments
Expiring
|
|
Total
Amounts
Committed
at
June 30, 2006
|
|
Less
Than
1
Year
|
|
1
to
3
Years
|
|
4
to
5
Years
|
|
Over
5
Years
|
|
Guarantees
of
subsidiary debt
|
|
$
|
178.4
|
|
$
|
150.0
|
|
$
|
-
|
|
$
|
-
|
|
$
|
28.4
|
|
Guarantees
supporting commodity transactions of subsidiaries
|
|
|
1,206.5
|
|
|
1,076.0
|
|
|
58.3
|
|
|
13.6
|
|
|
58.6
|
|
Standby
letters of credit
|
|
|
81.2
|
|
|
76.6
|
|
|
4.6
|
|
|
-
|
|
|
-
|
|
Surety
bonds
|
|
|
0.9
|
|
|
0.3
|
|
|
0.6
|
|
|
-
|
|
|
-
|
|
Other
guarantees
|
|
|
12.4
|
|
|
-
|
|
|
-
|
|
|
12.4
|
|
|
-
|
|
Total
guarantees
|
|
$
|
1,479.4
|
|
$
|
1,302.9
|
|
$
|
63.5
|
|
$
|
26.0
|
|
$
|
87.0
|
|
At
June 30, 2006, WPS Resources had outstanding $178.4 million in
corporate guarantees supporting indebtedness. Of that total, $150.0 million
supports an ESI 364-day credit agreement entered into in April 2006, to finance
its margin requirements related to natural gas and electric contracts traded
on
the NYMEX and the ICE, as well as the cost of natural gas in storage and
for
general corporate purposes. Borrowings under this agreement are guaranteed
by
WPS Resources and are subject to the aggregate $1.5 billion guarantee limit
authorized for ESI by WPS Resources' Board of Directors (discussed below).
As of June 30, 2006, the entire $150 million has been borrowed by ESI,
leaving no availability left on the existing credit agreement. Another
$28.4 million of guarantees supports outstanding debt at ESI's
subsidiaries, of which $1.1 million is subject to the $1.5 billion limit.
The
underlying debt related to these guarantees is reflected on WPS Resources'
Condensed Consolidated Balance Sheet.
WPS Resources'
Board of Directors has authorized management to issue corporate guarantees
in
the aggregate amount of up to $1.5 billion to support the business
operations of ESI. WPS Resources primarily issues the guarantees to
counterparties in the wholesale electric and natural gas marketplace to provide
them assurance that ESI will perform on its obligations and permit ESI to
operate within these markets. At June 30, 2006, WPS Resources provided
parental guarantees subject to this limit in the amount of
$1,311.8 million, reflected in the above table, for ESI's indemnification
obligations for business operations and for the $150 million credit
agreement discussed above. In addition, WPS Resources also provides
parental guarantees for ESI of $8.1 million that received specific
authorization from WPS Resources' Board of Directors and are not included
in the $1.5 billion general authorized amount. Of the parental guarantees
provided by WPS Resources, the current amount at June 30, 2006, which
WPS Resources would be obligated to support, is approximately
$312.8 million.
Another
$2.7 million of corporate guarantees support energy and transmission supply
at UPPCO and are not reflected on WPS Resources' Condensed Consolidated
Balance Sheet. 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.
Both
MGUC and MERC
have been authorized to issue corporate guarantees in the aggregate amount
of up
to $50 million each to support their business operations. At June 30,
2006, MGUC had $21.0 million of outstanding guarantees related to natural
gas supply. MERC had $12.9 million of outstanding guarantees related to
natural gas supply at June 30, 2006.
At
WPS Resources' request, financial institutions have issued
$81.2 million in standby letters of credit for the benefit of third
parties that have extended credit to certain subsidiaries. Of this amount,
$75.7 million has been issued to support ESI's operations. Included in the
$75.7 million is $2.5 million that has specific authorization from
WPS Resources Board of Directors and is not included in the
$1.5 billion guarantee limit. The remaining $73.2 million counts
against the $1.5 billion guarantee limit authorized for ESI. 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 WPS Resources' Condensed
Consolidated Balance Sheet.
At
June 30, 2006, WPS Resources furnished $0.9 million of surety
bonds for various reasons including worker compensation coverage and obtaining
various licenses, permits, and rights-of-way. Of the $0.9 million of surety
bonds, $0.3 million supports ESI and is included in the $1.5 billion
guarantee limit authorized for ESI. Liabilities incurred as a result of
activities covered by surety bonds are included in the WPS Resources'
Condensed Consolidated Balance Sheet.
A
guarantee of $4.4 million listed in the above table under other guarantees
was issued by WPSC to indemnify a third party for exposures related to the
construction of utility assets. This amount is not reflected on
WPS Resources' Condensed Consolidated Balance Sheet, as this agreement was
entered into prior to the effective date of FASB Interpretation No. 45.
In
conjunction with the sale of Kewaunee, WPSC and Wisconsin Power and Light
agreed
to indemnify Dominion for 70% of any and all reasonable costs 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 Wisconsin
Power and Light. 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,
or $8.9 million, as a component of the loss on the sale of Kewaunee. WPSC
has paid a total of $0.9 million to Dominion related to this guarantee,
reducing the liability to $8.0 million as of June 30,
2006.
Under
the sales
agreement with Corona Power, LLC relating to the sale of Sunbury, ESI agreed
to
indemnify Corona for losses resulting from potential breaches of ESI's
representations and warranties thereunder. This indemnification obligation
is
capped at $30 million for the first two years and then $5 million for
years three and four. ESI believes the likelihood of having to make any material
cash payments under the sales agreement as a result of breaches of
representations and warranties is remote.
NOTE
13--EMPLOYEE BENEFIT PLANS
The
following table
provides the components of net periodic benefit cost for WPS Resources'
benefit plans for the three months ended June 30:
WPS Resources
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
6.0
|
|
$
|
5.8
|
|
$
|
1.7
|
|
$
|
2.0
|
|
Interest
cost
|
|
|
10.4
|
|
|
10.1
|
|
|
4.6
|
|
|
4.1
|
|
Expected
return on plan assets
|
|
|
(10.9
|
)
|
|
(10.9
|
)
|
|
(3.5
|
)
|
|
(3.2
|
)
|
Amortization
of transition obligation
|
|
|
-
|
|
|
-
|
|
|
0.1
|
|
|
0.1
|
|
Amortization
of prior-service cost (credit)
|
|
|
1.3
|
|
|
1.3
|
|
|
(0.6
|
)
|
|
(0.6
|
)
|
Amortization
of net loss
|
|
|
3.0
|
|
|
2.3
|
|
|
1.6
|
|
|
1.7
|
|
Net
periodic
benefit cost
|
|
$
|
9.8
|
|
$
|
8.6
|
|
$
|
3.9
|
|
$
|
4.1
|
|
WPSC's
share of net
periodic benefit cost for the three months ended June 30 is included in the
table below:
WPSC
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
4.6
|
|
$
|
4.7
|
|
$
|
1.5
|
|
$
|
2.0
|
|
Interest
cost
|
|
|
8.2
|
|
|
8.4
|
|
|
3.6
|
|
|
3.7
|
|
Expected
return on plan assets
|
|
|
(8.9
|
)
|
|
(9.5
|
)
|
|
(3.3
|
)
|
|
(3.1
|
)
|
Amortization
of transition obligation
|
|
|
-
|
|
|
-
|
|
|
0.1
|
|
|
0.1
|
|
Amortization
of prior-service cost (credit)
|
|
|
1.2
|
|
|
1.2
|
|
|
(0.5
|
)
|
|
(0.5
|
)
|
Amortization
of net loss
|
|
|
1.9
|
|
|
1.5
|
|
|
1.1
|
|
|
1.5
|
|
Net
periodic
benefit cost
|
|
$
|
7.0
|
|
$
|
6.3
|
|
$
|
2.5
|
|
$
|
3.7
|
|
The
following table
provides the components of net periodic benefit cost for WPS Resources'
benefit plans for the six months ended June 30:
WPS Resources
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
11.8
|
|
$
|
11.9
|
|
$
|
3.5
|
|
$
|
4.0
|
|
Interest
cost
|
|
|
20.4
|
|
|
20.2
|
|
|
8.5
|
|
|
8.3
|
|
Expected
return on plan assets
|
|
|
(21.4
|
)
|
|
(21.8
|
)
|
|
(6.6
|
)
|
|
(6.3
|
)
|
Amortization
of transition obligation
|
|
|
0.1
|
|
|
0.1
|
|
|
0.2
|
|
|
0.2
|
|
Amortization
of prior-service cost (credit)
|
|
|
2.6
|
|
|
2.7
|
|
|
(1.1
|
)
|
|
(1.1
|
)
|
Amortization
of net loss
|
|
|
5.1
|
|
|
4.3
|
|
|
2.6
|
|
|
2.8
|
|
Net
periodic
benefit cost
|
|
$
|
18.6
|
|
$
|
17.4
|
|
$
|
7.1
|
|
$
|
7.9
|
|
WPSC's
share of net
periodic benefit cost for the six months ended June 30 is included in the
table below:
WPSC
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(Millions)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Net
periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
9.2
|
|
$
|
9.7
|
|
$
|
3.3
|
|
$
|
3.8
|
|
Interest
cost
|
|
|
16.4
|
|
|
16.7
|
|
|
7.1
|
|
|
7.5
|
|
Expected
return on plan assets
|
|
|
(18.0
|
)
|
|
(19.2
|
)
|
|
(6.4
|
)
|
|
(6.1
|
)
|
Amortization
of transition obligation
|
|
|
0.1
|
|
|
0.1
|
|
|
0.2
|
|
|
0.2
|
|
Amortization
of prior-service cost (credit)
|
|
|
2.3
|
|
|
2.4
|
|
|
(1.0
|
)
|
|
(1.0
|
)
|
Amortization
of net loss
|
|
|
3.3
|
|
|
2.9
|
|
|
2.0
|
|
|
2.4
|
|
Net
periodic
benefit cost
|
|
$
|
13.3
|
|
$
|
12.6
|
|
$
|
5.2
|
|
$
|
6.8
|
|
Contributions
to
the plans are made in accordance with legal and tax requirements and do not
necessarily occur evenly throughout the year. For the six months ended
June 30, 2006, $2.7 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 $22.6 million
to its pension plan and $17.9 million to its other postretirement benefit
plans in the remainder of 2006.
NOTE
14--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"). Under the provisions
of the 2005 Omnibus Plan, the number of shares of stock that may be issued
in satisfaction of plan awards may not exceed 1,600,000. No additional
awards 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. The number of shares issuable under each of the
aforementioned stock-based compensation plans, each outstanding award, and
stock
option exercise prices are subject to adjustment, at the Board of Directors’
discretion, in the event of any stock split, stock dividend, or other similar
transaction. At June 30, 2006, only stock options and performance stock
rights were outstanding under the aforementioned plans.
Prior
to January 1,
2006, WPS Resources accounted for the plans under the recognition and
measurement provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees." Accordingly, WPS Resources
provided pro forma disclosure amounts in accordance with SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure," as
if the
fair value method defined by SFAS No. 123, "Accounting for Stock-Based
Compensation," had been applied.
Effective
January
1, 2006, WPS Resources adopted the fair value recognition provisions of
SFAS No. 123R, "Share-Based Payment," using the modified prospective
transition method. Under this transition method, prior periods' results are
not
restated. Stock-based compensation cost for 2006
includes
compensation cost for all stock-based compensation awards granted prior to,
but
not yet fully vested as of January 1, 2006, based on the grant date fair
value
estimated in accordance with the original provisions of SFAS No. 123,
adjusted for estimated future forfeitures. There was no material cumulative
effect of a change in accounting principle recorded upon adoption of SFAS
No
123R. Stock-based compensation cost for all awards granted after January
1,
2006, will be recognized based on the grant date fair value estimated in
accordance with the provisions of SFAS No. 123R. The implementation of SFAS
No. 123R had an immaterial impact on cash flows from operations and cash
flows
from financing activities.
The
following table
illustrates the effect on income available for common shareholders and earnings
per share for the second quarter of 2005, had WPS Resources applied the
fair value recognition provisions of SFAS No. 123:
(Millions,
except per share amounts)
|
|
Three
Months
Ended
June 30,
2005
|
|
Six
Months
Ended
June 30,
2005
|
|
|
|
|
|
|
|
Income
available for common shareholders
|
|
|
|
|
|
As
reported
|
|
$
|
23.9
|
|
$
|
89.8
|
|
Add:
Stock-based compensation expense
using
the intrinsic value method - net of tax
|
|
|
0.8
|
|
|
1.3
|
|
Deduct:
Stock-based compensation expense
using
the fair value method - net of tax
|
|
|
(0.4
|
)
|
|
(0.7
|
)
|
Pro
forma
|
|
$
|
24.3
|
|
$
|
90.4
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
|
|
|
|
|
|
As
reported
|
|
$
|
0.63
|
|
$
|
2.37
|
|
Pro
forma
|
|
|
0.64
|
|
|
2.39
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per common share
|
|
|
|
|
|
|
|
As
reported
|
|
$
|
0.62
|
|
$
|
2.35
|
|
Pro
forma
|
|
|
0.63
|
|
|
2.37
|
|
Stock
Options
Under
the
provisions of the 2005 Omnibus Plan, no single employee who is the chief
executive officer of WPS Resources or any of the other four highest
compensated officers of WPS Resources and its subsidiaries can be granted
options for more than 250,000 shares during any calendar year. Stock options
are
granted by the Compensation Committee of the Board of Directors and may be
granted at any time. No stock options will have a term longer than ten years.
The exercise price of each stock option is equal to the fair market value
of the
stock on the date the stock option is granted. Under the 2005 and 2001 Omnibus
Plans and the Employee Plan, one-fourth of the stock options granted vest
and
become exercisable each year on the anniversary of the grant date.
The
number of stock
options granted under the Director Plan may not exceed 100,000, and the
shares to be delivered will consist solely of treasury shares. Stock options
are
granted at the discretion of the Board of Directors. No additional options
may be granted under this plan. All options have a ten-year term, but they
may not be exercised until one year after the date of grant. Options
granted under this plan are immediately vested. The exercise price of each
option is equal to the fair market value of the stock on the date the stock
options were granted.
The
fair values of
stock option awards outstanding at January 1, 2006, were estimated using
the
Black-Scholes option-pricing model. Stock options granted after the
implementation of SFAS No. 123R will be valued using a binomial lattice
model. No stock options were granted during the six months ended June 30,
2006, and no modifications were made to previously issued awards. Total pre-tax
compensation expense recognized for stock options during the three and six
months ended June 30, 2006, was $0.2 million and $0.3 million,
respectively, of which $0.1 million and $0.2 million, respectively,
relates to WPSC. The total compensation cost capitalized for these same periods
was immaterial.
As
of June 30, 2006, $1.2 million of total pre-tax compensation cost
related to unvested and outstanding stock options is expected to be recognized
over a weighted-average period of 2.6 years.
Cash
received from
option exercises was immaterial during the three and six months ended
June 30, 2006. The tax benefit realized from these option exercises was
also immaterial for the three and six months ended June 30,
2006.
A
summary of stock option activity for the six months ended June 30, 2006, is
presented below:
|
|
Stock
Options
|
|
Weighted-Average
Exercise Price Per Share
|
|
Weighted
Average Remaining Contractual Life (in
Years)
|
|
Aggregate
Intrinsic Value
(Millions)
|
|
Outstanding
at
December 31, 2005
|
|
|
|
|
|
|
|
|
|
2001
Omnibus
Plan
|
|
|
1,194,441
|
|
$
|
41.72
|
|
|
|
|
|
|
|
2005
Omnibus
Plan
|
|
|
325,347
|
|
|
54.85
|
|
|
|
|
|
|
|
Employee
Plan
|
|
|
156,973
|
|
|
33.99
|
|
|
|
|
|
|
|
Director
Plan
|
|
|
12,000
|
|
|
25.50
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001
Omnibus
Plan
|
|
|
13,264
|
|
|
38.73
|
|
|
|
|
$
|
0.2
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001
Omnibus
Plan
|
|
|
250
|
|
|
44.73
|
|
|
|
|
|
-
|
|
Outstanding
at
June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001
Omnibus
Plan
|
|
|
1,180,927
|
|
|
41.75
|
|
|
7.05
|
|
|
9.3
|
|
2005
Omnibus
Plan
|
|
|
325,347
|
|
|
54.85
|
|
|
9.44
|
|
|
-
|
|
Employee
Plan
|
|
|
156,973
|
|
|
33.99
|
|
|
4.23
|
|
|
2.5
|
|
Director
Plan
|
|
|
12,000
|
|
|
25.50
|
|
|
3.24
|
|
|
0.3
|
|
Options
exercisable at June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001
Omnibus
Plan
|
|
|
698,849
|
|
|
39.31
|
|
|
6.55
|
|
|
7.2
|
|
Employee
Plan
|
|
|
156,973
|
|
|
33.99
|
|
|
4.23
|
|
|
2.5
|
|
Director
Plan
|
|
|
12,000
|
|
|
25.50
|
|
|
3.24
|
|
|
0.3
|
|
No
options expired during the six months ended June 30, 2006.
The
aggregate
intrinsic value for outstanding and exercisable options in the above table
represents the total pre-tax intrinsic value that would have been received
by
the option holders had they all exercised their options at June 30, 2006.
This is calculated as the difference between WPS Resources' closing stock
price on June 30, 2006, and the option exercise price, multiplied by the
number of in-the-money stock options.
Other
Stock-Based Compensation Awards
A
portion of the long-term incentive is awarded in the form of performance
stock
rights. No more than 400,000 of the shares authorized for issuance under
the
provisions of the 2005 Omnibus Plan can be granted as performance shares.
In
addition, no single employee who is the chief executive officer of
WPS Resources or any of the other four highest compensated officers of
WPS Resources and its subsidiaries can receive a payout in excess of 50,000
performance shares during any calendar year. Performance stock rights vest
over
a three-year performance period and are paid out in shares of
WPS Resources' common stock. The number of shares paid out is calculated by
multiplying a performance percentage by the number of outstanding stock rights
at the completion of the vesting period. The performance multiplier is based
on
the total shareholder return of WPS Resources' common stock relative to the
total shareholder return of a peer group of companies. The payout may range
from 0% to 200% of target.
The
fair values of
performance stock right awards outstanding at January 1, 2006, were estimated
using WPS Resources' common stock price on the date of grant, less the
present value of expected dividends over the three-year vesting period, assuming
a payout of 100% of target. Performance stock rights
granted
after the
implementation of SFAS No. 123R will be valued using the Monte Carlo
valuation model. No performance stock rights were granted during the six
months
ended June 30, 2006, and no modifications were made to previously issued
awards. Pre-tax compensation expense recorded for performance stock rights
for
the three months and six months ended June 30, 2006, was $0.7 million
and $1.3 million, respectively. For these same time periods
$0.4 million and $0.9 million relate to WPSC. The total compensation
cost capitalized was immaterial.
The
total intrinsic
value of performance shares distributed during the first quarter of 2006
(related to the December 2002 grant) was $2.4 million. The tax benefit
realized due to the distribution of performance shares totaled
$1.0 million. No performance shares were distributed during the second
quarter.
As
of June 30, 2006, $3.2 million of total pre-tax compensation cost
related to unvested and outstanding performance stock rights is expected
to be
recognized over a weighted-average period of 2.3 years.
A
summary of the activity of the performance stock rights plan for the six
months
ended June 30, 2006, is presented below:
|
|
Performance
Stock
Rights
|
|
Weighted-Average
Grant
Date Fair Value
|
|
Outstanding
at December 31, 2005
|
|
|
211,421
|
|
$
|
41.93
|
|
Distributed
|
|
|
37,600
|
|
|
31.60
|
|
Forfeited
|
|
|
800
|
|
|
45.84
|
|
Outstanding
at June 30, 2006
|
|
|
173,021
|
|
$
|
44.15
|
|
Performance
stock
rights vested at December 31, 2005, were paid out during the first quarter
of 2006. The actual number of shares of WPS Resources' common stock
distributed totaled 45,121 based on a payout of 120% of target. None of the
stock rights outstanding at June 30, 2006, were exercisable at
June 30, 2006.
NOTE
15--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
June 30,
|
|
(Millions)
|
|
2006
|
|
2005
|
|
Income
available for common shareholders
|
|
$
|
34.9
|
|
$
|
23.9
|
|
Cash
flow
hedges, net of tax of $7.6 and $1.7
|
|
|
11.8
|
|
|
2.9
|
|
Foreign
currency translation
|
|
|
0.3
|
|
|
0.4
|
|
Unrealized
gain on available-for-sale securities, net of tax of
$0.1 for
both periods
|
|
|
(0.2
|
)
|
|
(0.1
|
)
|
Total
comprehensive income
|
|
$
|
46.8
|
|
$
|
27.1
|
|
|
|
Six
Months
Ended
June 30,
|
|
(Millions)
|
|
2006
|
|
2005
|
|
Income
available for common shareholders
|
|
$
|
95.0
|
|
$
|
89.8
|
|
Cash
flow
hedges, net of tax of $19.6 and $(7.0)
|
|
|
30.4
|
|
|
(10.7
|
)
|
Foreign
currency translation
|
|
|
0.3
|
|
|
(0.3
|
)
|
Unrealized
gain on available-for-sale securities, net of tax of
$0.1 for
2005
|
|
|
-
|
|
|
0.1
|
|
Total
comprehensive income
|
|
$
|
125.7
|
|
$
|
78.9
|
|
The
following table
shows the changes to accumulated other comprehensive income from
December 31, 2005, to June 30, 2006.
(Millions)
|
|
|
|
December 31,
2005 balance
|
|
$
|
(10.4
|
)
|
Cash
flow
hedges
|
|
|
30.4
|
|
Foreign
currency translation
|
|
|
0.3
|
|
June 30,
2006 balance
|
|
$
|
20.3
|
|
NOTE
16--COMMON EQUITY
WPS Resources'
common stock shares, $1 par value
|
|
June 30,
2006
|
|
December 31,
2005
|
|
Common
stock
outstanding, $1 par value, 200,000,000 shares authorized
|
|
|
43,122,346
|
|
|
40,089,898
|
|
Treasury
shares
|
|
|
12,000
|
|
|
12,000
|
|
Average
cost
of treasury shares
|
|
$
|
25.19
|
|
$
|
25.19
|
|
Shares
in
deferred compensation rabbi trust
|
|
|
304,832
|
|
|
270,491
|
|
Average
cost
of deferred compensation rabbi trust shares
|
|
$
|
42.03
|
|
$
|
40.29
|
|
Basic
earnings per
share are 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 are 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, performance stock rights, and shares related to the forward equity
transaction. The calculation of diluted earnings per share for the periods
shown
excludes some stock option and performance stock rights that had an
anti-dilutive effect. The shares having an anti-dilutive effect are not
significant for any of the periods shown. The following tables reconcile
the
computation of basic and diluted earnings per share:
|
|
Three
Months Ended June 30
|
|
Six
Months Ended June 30
|
|
(in millions,
except per share amounts)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Income
available to common stockholders
|
|
$34.9
|
|
$23.9
|
|
$95.0
|
|
$89.8
|
|
|
|
|
|
|
|
|
|
|
|
Basic
EPS
|
|
|
|
|
|
|
|
|
|
Average
shares of common stock outstanding - basic
|
|
|
42.2
|
|
|
38.0
|
|
|
41.2
|
|
|
37.9
|
|
Income
from
continuing operations
|
|
$
|
0.96
|
|
$
|
0.75
|
|
$
|
2.41
|
|
$
|
2.38
|
|
Discontinued
operations, net of tax
|
|
|
(0.13
|
)
|
|
(0.12
|
)
|
|
(0.10
|
)
|
|
(0.01
|
)
|
Earnings
per
common share (basic)
|
|
$
|
0.83
|
|
$
|
0.63
|
|
$
|
2.31
|
|
$
|
2.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
EPS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares of common stock outstanding
|
|
|
42.2
|
|
|
38.0
|
|
|
41.2
|
|
|
37.9
|
|
Effect
of
diluted securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance stock rights and stock options
|
|
|
-
|
|
|
0.4
|
|
|
0.1
|
|
|
0.3
|
|
Average
shares of common stock outstanding - diluted
|
|
|
42.2
|
|
|
38.4
|
|
|
41.3
|
|
|
38.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
0.96
|
|
$
|
0.74
|
|
$
|
2.41
|
|
$
|
2.36
|
|
Discontinued
operations, net of tax
|
|
|
(0.13
|
)
|
|
(0.12
|
)
|
|
(0.11
|
)
|
|
(0.01
|
)
|
Earnings
per
common share (diluted)
|
|
$
|
0.83
|
|
$
|
0.62
|
|
$
|
2.30
|
|
$
|
2.35
|
|
In
November 2005, WPS Resources entered into a forward equity sale agreement
with an affiliate of J. P. Morgan Securities, Inc., as forward
purchaser, relating to 2.7 million shares of WPS Resources' common
stock. On May 10, 2006, WPS Resources physically settled the forward equity
agreement (and, thereby, issued 2.7 million shares of common stock) and
received proceeds of $139.6 million. The
proceeds
were used
to pay down commercial paper borrowings originally utilized to finance the
acquisition of the natural gas distribution operations in Michigan and for
general corporate purposes.
NOTE
17--REGULATORY ENVIRONMENT
Wisconsin
On
April 25, 2006, WPSC filed with the PSCW a stipulation agreement with various
interveners to refund a portion of the difference between fuel costs that
were
projected in the 2006 Wisconsin retail rate case and actual Wisconsin retail
fuel costs incurred from January through March 2006 as well as the
projected fuel savings in April through June 2006. This refund results in a
credit to customers' bills over the months of May 2006 to August 2006. A
current regulatory liability of $3.1 million has been recorded at
June 30, 2006, and $4.6 million was refunded to customers in the
second quarter of 2006, related to the stipulation agreement. Rates remain
subject to refund under the agreement through the end of the year.
On
March 31, 2006, WPSC filed a request with the PSCW to increase retail
electric and natural gas rates 14.4% ($125.1 million) and 3.9%
($22.6 million), respectively for 2007. Since then, WPSC adjusted the
request to 15.8% ($136.9 million) due to higher than expected coal costs
and Weston 3 maintenance costs. The proposed retail electric rate increase
is
required because of increased costs associated with electric transmission,
(including the recovery of 2007 MISO costs and deferred MISO costs from 2005
and
2006), higher fuel and purchased power costs (including the recovery of deferred
costs for reduced coal deliveries in 2005), costs related to the construction
of
Weston 4 and the additional personnel to maintain and operate the plant,
and
costs to maintain the Weston 3 generation unit and the De Pere Energy Center.
The proposed retail natural gas rate increase is driven by infrastructure
improvements necessary to ensure the reliability of the natural gas distribution
system and remediation of former manufactured gas sites. This filing included
an
11.0% return on common equity and a common equity ratio of 60.35% in its
regulatory capital structure. Hearings on this request have been scheduled
for
September 2006, and WPSC anticipates the new rates to be effective January
1,
2007. In order to provide greater rate certainty for our customers through
2008,
WPSC filed a biennial rate proposal with the PSCW on July 1, 2006. The rate
proposal includes a revenue stabilization mechanism, which is designed to
reduce
over and under collections of WPSC's gross margin caused by variations in
the
weather. WPSC expects that the PSCW will act upon this proposal as part of
the
2007 rate case.
On
December 22, 2005, the PSCW issued a final written order authorizing a
retail electric rate increase of $79.9 million (10.1%) and a retail natural
gas rate increase of $7.2 million (1.1%), effective January 1, 2006. The
2006 rates reflect an 11.0% return on common equity. The PSCW also approved
a
common equity ratio of 59.7% in its regulatory capital structure. The 2006
retail electric rate increase was required primarily because of higher fuel
and
purchased power costs (including costs associated with the Fox Energy Center
power purchase agreement), and also for costs related to the construction
of
Weston 4, higher transmission expenses, and recovery of a portion of the
costs related to the 2005 Kewaunee outage. Partially offsetting the items
discussed above, retail electric rates were lowered to reflect a refund to
customers in 2006 of a portion of the proceeds received from the liquidation
of
the nonqualified decommissioning trust fund as a result of the sale of Kewaunee.
The 2006 retail natural gas rate increase was driven by infrastructure
improvements necessary to ensure the reliability of the natural gas distribution
system.
On
June 7, 2005, WPSC filed with the PSCW, the MPSC, and the FERC a request
for establishment of a cooperative joint proceeding for approval of the Kewaunee
wind-up plan. The wind-up plan proposed that the refunds due to both retail
and
wholesale customers related to proceeds received from the liquidation of
the
nonqualified decommissioning trust fund be offset by the net loss on the
sale of
the plant and also by certain costs related to the 2004 and 2005 Kewaunee
outages. The wind-up plan proposed 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 (January 1, 2006). The FERC subsequently denied the request
for
joint proceeding with the PSCW. The wind-up plan was addressed by the PSCW
in
WPSC's 2006 rate case (discussed above). The PSCW ruled in the 2006 rate
case
that the deferred assets and liabilities related to the Kewaunee matters
should
be treated separately and not netted as WPSC initially proposed in its wind-up
plan. In the 2006 rate case, the PSCW determined that Wisconsin retail customers
were entitled to be
refunded
approximately 85% of the proceeds received from the liquidation of the
nonqualified decommissioning trust fund based on a historical allocation
methodology, or approximately $108 million of the total $127.1 million
of proceeds received, over a two-year period beginning on January 1, 2006
(in
addition to the refund of carrying costs on the unamortized balance at the
authorized pre-tax weighted average cost of capital). In 2005, the MPSC ruled
that WPSC's Michigan customers were entitled to be refunded approximately
2% of
the proceeds received from the liquidation of the nonqualified decommissioning
fund over a 60-month period. Refunding to Michigan customers began in the
third
quarter of 2005.
On
August 8, 2005, the FERC accepted the proposed refund plan for filing and
implemented the plan effective January 1, 2006, subject to refund upon final
resolution. Settlement discussions between WPSC and wholesale parties contesting
WPSC's refund plan were held both in the fourth quarter of 2005 and in the
first
quarter of 2006, and final resolution was reached between WPSC and one party
on
this matter. On April 25, 2006, formal settlement discussions were terminated
with the remaining parties. On May 19, 2006, WPSC filed a proposed amendment
to
revise the manner of distributing the value of the non-qualified decommissioning
trust related to the Kewaunee plant. Instead of providing refunds as a credit
to
wholesale customers' future bills, WPSC proposed to refund the value of the
non-qualified decommissioning trust based on historical customer payments
paid
into the trust fund. WPSC also proposed to reduce the amortization period
of the
refund from five years, as originally proposed, to two years. In addition,
on
May 24, 2006, WPSC filed a motion to consolidate the June 2005 proceeding
with the instant proceeding for purposes of hearing and decision and to expedite
the instant proceeding so that the litigation on both proceedings may be
conducted on a timely basis. On June 30, 2006, the FERC accepted WPSC's
wind-up plan amendment, and suspended it until August 1, 2006. The FERC also
granted WPSC's request for consolidation. Final resolution of the case is
not
anticipated until 2007.
At
June 30, 2006, WPSC had recorded a $96.8 million regulatory liability
representing the amount of proceeds received from the liquidation of the
nonqualified decommissioning trust fund remaining to be refunded to both
retail
and wholesale customers.
Michigan
On
June 27, 2006, the MPSC issued a final written order authorizing a retail
electric rate increase for UPPCO of $3.8 million (4.8%), effective
June 28, 2006. The 2006 rate reflects a 10.75% return on common equity. The
MPSC also approved a common equity ratio of 54.9% in its regulatory capital
structure. The retail electric rate increase was required in order to improve
service quality and reliability, upgrade technology, and manage rising employee
and retiree benefit costs. UPPCO's last retail electric rate increase was
in
December 2002.
The
increased
retail electric rate does not reflect the recovery by UPPCO of any deferred
costs associated with the Silver Lake incident, which will be addressed in
a
future proceeding.
Federal
Through
a series of
orders issued by the 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 rate elimination, the FERC ordered a
transitional pricing mechanism called the Seams Elimination Charge Adjustment
(SECA) to be put into place. Load-serving entities paid these SECA charges
during a 16-month transition period from December 1, 2004, through
March 31, 2006.
For
the 16-month
transitional period, ESI received billings of $19.2 million for these
charges, of which approximately $17 million relates to its Michigan retail
electric business and $2 million relates to Ohio retail electric business.
ESI expensed $14.7 million of the $19.2 million. It is probable that
ESI's total exposure will be reduced by at least $4.5 million due to
inconsistencies between the FERC's SECA order and the transmission owners'
compliance filings. ESI anticipates settling a significant portion of its
SECA
matters through vendor negotiations in 2006 and reached a $1.0 million
settlement agreement with one of its vendors in January 2006. Resolution
of
issues to be raised in an upcoming 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 been doing so. Since SECA is a transition charge that
ended
on March 31, 2006, it does not directly impact ESI's long-term
competitiveness. The application and legality of the SECA is being challenged
by
many load-serving entities, including ESI and ESI continues to pursue all
avenues to appeal and/or reduce the SECA obligations.
The
SECA is also an
issue for WPSC and UPPCO, who have intervened and protested a number of
proposals in this docket because they believe those proposals could result
in
unjust, unreasonable, and discriminatory charges for customers. It is
anticipated that most of the SECA rate charges incurred by WPSC and UPPCO
and
any refunds will be passed on to customers through rates. WPSC and UPPCO
have
reached a settlement in principle with American Electric Power and Commonwealth
Edison, which was certified by the settlement judge and now awaits approval
by
the FERC. Under the terms of the settlement agreement, American Electric
Power
and Commonwealth Edison will refund almost $1 million of the approximately
$4 million paid by WPSC during the transition period.
NOTE
18--SEGMENTS OF BUSINESS
We
manage our reportable segments separately due to their different operating
and
regulatory environments. Prior to the fourth quarter of 2005, WPS Resources
reported two nonregulated segments, ESI and WPS Power Development. In the
fourth quarter of 2005, WPS Resources' Chief Executive Officer and its
Board of Directors decided to view ESI and WPS Power Development as one
business; therefore, corresponding changes were made to the segment information
reported to them. Effective in the fourth quarter of 2005, WPS Resources
began reporting to the Chief Executive Officer and Board of Directors one
nonregulated segment, ESI. Segment information related to prior periods has
been
reclassified to reflect this change.
Our
two regulated
segments include the regulated electric utility operations of WPSC and UPPCO,
and the regulated natural gas utility operations of WPSC, MGUC, and certain
transition costs related to the acquisition of the retail natural gas
distribution operations in Minnesota from Aquila. As discussed above, ESI
is our
primary nonregulated segment offering natural gas, electric, and alternate
fuel
supplies as well as energy management and consulting services to retail and
wholesale customers, and marketing power from its generation plants that
are not
under contract to third parties. The Other segment, another nonregulated
segment, includes the operations of WPS Resources and WPS Resources
Capital Corporation as holding companies, along with nonutility activities
at
WPSC, MGUC, and UPPCO.
|
|
Regulated
Utilities
|
|
Nonutility
and Nonregulated Operations
|
|
|
|
|
|
Segments
of Business
(Millions)
|
|
Electric
Utility(1)
|
|
Gas
Utility(1)
|
|
Total
Utility(1)
|
|
ESI(2)
|
|
Other(1)
|
|
Reconciling
Eliminations
|
|
WPS Resources
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
June 30,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
254.1
|
|
$
|
95.4
|
|
$
|
349.5
|
|
$
|
1,129.5
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,479.0
|
|
Intersegment
revenues
|
|
|
8.3
|
|
|
0.2
|
|
|
8.5
|
|
|
4.6
|
|
|
0.3
|
|
|
(13.4
|
)
|
|
-
|
|
Income
from
continuing operations
|
|
|
24.0
|
|
|
(7.3
|
)
|
|
16.7
|
|
|
19.0
|
|
|
5.6
|
|
|
-
|
|
|
41.3
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(5.6
|
)
|
|
-
|
|
|
-
|
|
|
(5.6
|
)
|
Income
available for common shareholders
|
|
|
23.4
|
|
|
(7.5
|
)
|
|
15.9
|
|
|
13.4
|
|
|
5.6
|
|
|
-
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months
Ended
June 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
231.8
|
|
$
|
89.6
|
|
$
|
321.4
|
|
$
|
993.1
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,314.5
|
|
Intersegment
revenues
|
|
|
8.4
|
|
|
0.2
|
|
|
8.6
|
|
|
2.2
|
|
|
0.3
|
|
|
(11.1
|
)
|
|
-
|
|
Income
from
continuing operations
|
|
|
21.4
|
|
|
(1.6
|
)
|
|
19.8
|
|
|
8.3
|
|
|
1.3
|
|
|
-
|
|
|
29.4
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(4.7
|
)
|
|
-
|
|
|
-
|
|
|
(4.7
|
)
|
Income
available for common shareholders
|
|
|
20.9
|
|
|
(1.9
|
)
|
|
19.0
|
|
|
3.6
|
|
|
1.3
|
|
|
-
|
|
|
23.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
June 30,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
500.3
|
|
$
|
288.3
|
|
$
|
788.6
|
|
$
|
2,691.5
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,480.1
|
|
Intersegment
revenues
|
|
|
18.5
|
|
|
0.3
|
|
|
18.8
|
|
|
5.8
|
|
|
0.6
|
|
|
(25.2
|
)
|
|
-
|
|
Income
from
continuing operations
|
|
|
39.9
|
|
|
(0.2
|
)
|
|
39.7
|
|
|
54.9
|
|
|
6.4
|
|
|
-
|
|
|
101.0
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(4.4
|
)
|
|
-
|
|
|
-
|
|
|
(4.4
|
)
|
Income
available for common shareholders
|
|
|
38.9
|
|
|
(0.8
|
)
|
|
38.1
|
|
|
50.5
|
|
|
6.4
|
|
|
-
|
|
|
95.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months
Ended
June 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
468.2
|
|
$
|
264.1
|
|
$
|
732.3
|
|
$
|
2,044.3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
2,776.6
|
|
Intersegment
revenues
|
|
|
16.0
|
|
|
0.3
|
|
|
16.3
|
|
|
3.3
|
|
|
0.6
|
|
|
(20.2
|
)
|
|
-
|
|
Income
from
continuing operations
|
|
|
45.4
|
|
|
12.7
|
|
|
58.1
|
|
|
32.3
|
|
|
1.5
|
|
|
-
|
|
|
91.9
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(0.5
|
)
|
|
-
|
|
|
-
|
|
|
(0.5
|
)
|
Income
available for common shareholders
|
|
|
44.4
|
|
|
12.1
|
|
|
56.5
|
|
|
31.8
|
|
|
1.5
|
|
|
-
|
|
|
89.8
|
|
(1)
Includes
only utility operations. Nonutility operations are included in the Other
column.
(2) All
revenue and
costs of ESI's discontinued operations are combined and reported on a net
basis
in the Condensed Consolidated Statements of Income for all periods presented.
Accordingly, the above table does not reflect revenues from discontinued
operations, but the results from discontinued operations are included as
a
component of ESI's income in the table. Nonregulated revenues reclassified
to
discontinued operations for the three months ended June 30, 2006 and
June 30, 2005, were $22.5 million and $13.0 million,
respectively, and were $59.4 million and $37.8 million, for the six
months ended June 30, 2006 and June 30, 2005, respectively.
WPSC's
principal
business segments are the regulated electric utility operations and the
regulated natural 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
June 30,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
238.9
|
|
$
|
68.0
|
|
$
|
306.9
|
|
$
|
0.3
|
|
|
($0.3
|
)
|
$
|
306.9
|
|
Earnings
on
common stock
|
|
|
23.7
|
|
|
(2.2
|
)
|
|
21.5
|
|
|
3.6
|
|
|
-
|
|
|
25.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months
Ended
June 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
219.3
|
|
$
|
89.8
|
|
$
|
309.1
|
|
$
|
0.3
|
|
$
|
(0.3
|
)
|
$
|
309.1
|
|
Earnings
on
common stock
|
|
|
20.6
|
|
|
(1.9
|
)
|
|
18.7
|
|
|
2.6
|
|
|
-
|
|
|
21.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
June 30,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
468.3
|
|
$
|
261.0
|
|
$
|
729.3
|
|
$
|
0.7
|
|
|
($0.7
|
)
|
$
|
729.3
|
|
Earnings
on
common stock
|
|
|
37.8
|
|
|
8.5
|
|
|
46.3
|
|
|
5.0
|
|
|
-
|
|
|
51.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months
Ended
June 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
439.1
|
|
$
|
264.4
|
|
$
|
703.5
|
|
$
|
0.7
|
|
$
|
(0.7
|
)
|
$
|
703.5
|
|
Earnings
on
common stock
|
|
|
43.0
|
|
|
12.1
|
|
|
55.1
|
|
|
3.8
|
|
|
-
|
|
|
58.9
|
|
(1)
|
Includes
only
utility operations. Nonutility operations are included in the Other
column.
|
NOTE
19--NEW ACCOUNTING PRONOUNCEMENTS
In
April 2006, the FASB issued FASB Staff Position No. FIN 46(R)-6,
"Determining the Variability to Be Considered in Applying FASB Interpretation
No. 46(R)." This Staff Position clarifies that a qualitative analysis of
the design of an entity should be used to determine the variability to be
considered in applying Interpretation No. 46(R), "Consolidation of Variable
Interest Entities." In particular, the following steps should be used as
the
basis for that determination: (1) analyze the nature of the risks in the
entity,
and (2) determine the purpose(s) for which the entity was created and
determine the variability (created by the risks identified in step (1)) the
entity is designed to create and pass along to its interest holders. The
guidance is to be applied prospectively beginning the first day of the first
reporting period beginning after June 15, 2006. WPS Resources will
evaluate future transactions under the guidance stipulated in FASB Staff
Position No. FIN 46(R)-6.
In
September 2005, the FASB ratified the consensus reached by the EITF on
Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the
Same
Counterparty." This guidance addresses the following issues: (1) whether
two or
more exchange transactions involving inventory with the same counterparty
are
entered into in contemplation of one another and should be viewed as a single
exchange transaction within the scope of Accounting Principles Board Opinion
No. 29, "Accounting for Non-monetary Transactions," and (2) whether
non-monetary exchanges of inventory in the same line of business should be
recognized at fair value. This consensus is effective for all arrangements
entered into in reporting periods beginning after March 15, 2006, and for
modifications or renewals of existing arrangements after that date. Although
the
consensus did not impact WPS Resources' financial statements in the second
quarter, we will continue to evaluate future transactions under the guidance
of
Issue No. 04-13.
In
July 2006, the FASB issued Interpretation No. 48, "Accounting for Uncertainty
in
Income Taxes," to provide guidance on how to reflect uncertain tax positions
in
an enterprise's financial statements. The Interpretation applies to all tax
positions and will affect all circumstances in which an entity is uncertain
as
to whether a tax position will ultimately be sustained as filed in its tax
return. In order to recognize a tax benefit in the financial statements,
an
entity must determine that it is "more likely than not" that the tax benefit
will be realized. The amount of the tax benefit to be recognized is the largest
amount that is greater than 50% likely to be realized upon ultimate settlement
with the taxing authority. The Interpretation is effective for fiscal years
beginning after December 15, 2006. WPS Resources is currently
analyzing any impact this guidance may have on its financial
statements.
|
MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
|
|
CONDITION
AND RESULTS OF OPERATIONS
|
INTRODUCTION
- WPS RESOURCES
WPS Resources
is a diversified holding company operating through subsidiaries that provide
energy and related services. Our wholly owned subsidiaries include four
regulated utilities, WPSC, UPPCO, MGUC, and MERC, which was established to
purchase the retail natural gas distribution operations in Minnesota from
Aquila, Inc. (Aquila). Another wholly owned subsidiary, WPS Resources
Capital Corporation, is a holding company for our nonregulated ESI
subsidiary.
Strategic
Overview
The
focal point of
WPS Resources' business plan is the creation of long-term value for our
shareholders and our customers through growth, operational excellence, asset
management, risk management, and the continued emphasis on reliable,
competitively priced, and environmentally sound energy and energy related
services. We are seeking growth of our regulated and nonregulated portfolio
and
placing an emphasis on regulated growth.
A discussion of
the essential components of our business plan is set forth below.
Maintain
and Grow a Strong Regulated Utility Base
-
We
are focusing on
growth in our regulated operations. A strong regulated utility base is
important in order to maintain a strong balance sheet, predictable cash flows,
a
desired risk profile, attractive dividends, and quality credit ratings, which
are critical to our success. WPS Resources believes the following recent
developments have helped, or will help, maintain and grow its regulated utility
base:
·
|
In
July 2006,
WPS Resources entered into a definitive merger agreement with Peoples
Energy Corporation (Peoples Energy). See Note 5, "Acquisitions
and Sales of Assets,"
for more
information.
|
·
|
WPSC
is
expanding its regulated generation fleet in order to meet growing
electric
demand and ensure continued reliability. Construction of the 500-megawatt
coal-fired Weston 4 base-load power plant located near Wausau,
Wisconsin, continues in partnership with DPC. In addition, WPSC
is
pursuing plans to construct other electric generation facilities
in the
future, in particular to meet new energy efficiency and renewables
standards enacted in Wisconsin.
|
·
|
On
April 1,
2006, our subsidiary, MGUC, acquired Aquila's natural gas distribution
operations in Michigan and on July 1, 2006, our subsidiary, MERC,
acquired
Aquila's natural gas distribution operations in Minnesota. The
addition of
these regulated assets in close proximity to WPS Resources' existing
regulated electric and natural gas operations in Wisconsin and
Michigan
will transition WPS Resources to a larger and stronger regional
energy company.
|
·
|
We
have
invested in ATC and received additional equity interest as consideration
for funding a portion of the Duluth, Minnesota, to Wausau, Wisconsin,
transmission line.
|
·
|
WPSC
continues to invest in environmental projects to improve air quality
and
meet the requirements set by environmental regulators. Capital
projects to
construct and upgrade equipment to meet or exceed required environmental
standards are planned each year.
|
Integrate
Resources to Provide Operational Excellence
-
WPS Resources
is committed to integrating resources of its regulated business units and
also
its nonregulated business units, while maintaining any and all applicable
regulatory and legal restrictions. This will provide the best value to all
customers by leveraging the individual capabilities and expertise of each
unit
and assist in lowering costs for certain activities.
·
|
The
proposed
merger of WPS Resources and Peoples Energy will align the best
practices and expertise of both companies and result in efficiencies
by
eliminating redundant and overlapping functions and systems. The
merger is
expected to ultimately result in annual cost savings of approximately
$87 million in the regulated businesses and $7 million in the
nonregulated business. We anticipate achieving these ongoing synergies
approximately five years from the date of the merger and it is
expected
that one-time costs to obtain the synergies will be approximately
$186 million.
|
·
|
We
have
integrated resources at our nonregulated subsidiaries by restructuring
the
management teams of ESI and its subsidiary, WPS Power Development,
and taking measures to reduce merchant generation market
risk.
|
·
|
At
our
regulated business units, we are optimally sourcing work and combining
resources to achieve best practices at WPSC, UPPCO, MGUC and the
natural
gas distribution operations in Minnesota that were acquired by
MERC on
July 1, 2006, in order to achieve operational excellence and sustainable
value for customers and shareholders.
|
·
|
An
initiative
we call "Competitive Excellence" is being deployed across
WPS Resources and its subsidiaries. Competitive Excellence strives
to
eliminate work that does not provide value for customers. This
will create
more efficient processes, improve the effectiveness of employees,
and
reduce costs.
|
Strategically
Grow Nonregulated Businesses
-
ESI
will grow its
electric and natural gas business (through strategic acquisitions, penetration
in existing markets, and new product offerings) by targeting growth in areas
where it has market expertise and through "strategic hiring" in other areas.
ESI
also focuses on optimizing the operational efficiency of its existing portfolio
of assets and pursues compatible development projects that strategically
fit
with its customer base and market expertise.
·
|
The
proposed
merger of WPS Resources and Peoples Energy will comprise the
complementary nonregulated energy marketing businesses of both
companies.
By combining the energy marketing businesses, we will create a
stronger,
more competitive, and better balanced growth platform for our nonregulated
business.
|
·
|
ESI
began
offering retail electric products in 2006 primarily to large commercial
and industrial customers in Illinois, New Hampshire, and Rhode
Island. In
2005, ESI was only offering natural gas products and energy management
services to customers in Illinois and did not offer retail electric
products in New Hampshire and Rhode Island.
|
·
|
ESI
began
developing a product offering in the Texas retail electric market
in 2005.
Entry into Texas, with its thriving market structure, provides
ESI with an
opportunity to leverage the infrastructure and capability ESI developed
to
provide products and services that it believes customers will value.
ESI
continues to sign up new enrollments and started to deliver power
to
customers in the Texas market in July 2006.
|
·
|
ESI
began
marketing electric products to customers in Massachusetts in 2005
and has
had initial success in signing up commercial and industrial
customers.
|
·
|
ESI
continues
to grow its retail natural gas business in Canada through the addition
of
new customers.
|
Place
Strong Emphasis on Asset and Risk Management
-
Our asset management strategy calls for the continuous assessment of our
existing assets and the acquisition of assets that complement our existing
business and strategy. This strategy also calls for the disposition of assets,
including plants and entire business units, which are either no longer strategic
to ongoing operations, are not performing as needed, or the disposition of
which
would reduce our risk profile. We maintain a portfolio approach to risk and
earnings and expect our nonregulated operations to provide between 20 and
30
percent of our earnings, on average, in the future.
·
|
In
July 2006,
WPS Resources entered into a definitive merger agreement with Peoples
Energy. See Note 5, "Acquisitions
and Sales of Assets,"
for more
information. The combination of the two companies will create a
larger,
stronger, more competitive regional energy
company.
|
·
|
The
acquisition of the Michigan natural gas distribution operations
from
Aquila in April 2006, and the acquisition of the Minnesota natural
gas
distribution operations from Aquila in July 2006, will transition
WPS Resources into a larger and stronger regional energy
company.
|
·
|
On
July 26, 2006, ESI completed the sale of Sunbury Generation, LLC to
Corona Power, LLC, for $34.6 million, subject to certain working
capital and other post-closing adjustments. Sunbury Generation's
primary
asset was the Sunbury generation facility located in Pennsylvania.
The
transaction is anticipated to result in a pre-tax gain of approximately
$19 million in the third quarter of 2006. In addition, approximately
$14 million of cash tax benefits are expected to be realized over the
next few years, depending on the use of the alternative minimum
tax
credits. ESI management had been evaluating Sunbury's future since
2004
and after carefully reviewing alternatives and current business
conditions, determined that the sale was the best alternative.
|
·
|
In
April
2006, a subsidiary of WPS Resources completed the sale of its
one-third interest in Guardian Pipeline, LLC to Northern Border
Partners, LP for $38.5 million. The transaction resulted in a pre-tax
gain of $6.2 million which was recorded in the second quarter of
2006. We believe the sale provides a good opportunity to redeploy
the
proceeds into other investment opportunities providing value to
our
shareholders.
|
·
|
In
April 2006, ESI sold WPS ESI Gas Storage, LLC, which owns a
natural gas storage field located in the Kimball Township, St.
Clair
County, Michigan, recognizing a pre-tax gain of $9.0 million in the
second quarter of 2006. ESI utilized this facility primarily for
structured wholesale natural gas transactions as natural gas storage
spreads presented arbitrage opportunities. ESI was not actively
marketing
this facility for sale, but believed the price offered was above
the value
it would realize from continued ownership of the
facility.
|
·
|
We
continue
to evaluate alternatives for the sale of real estate holdings we
have
identified as no longer needed for our
operations.
|
Our
risk management
strategy, in addition to asset risk management, includes the management of
market, credit and operational risk through the normal course of business.
·
|
Forward
purchases and sales of electric capacity, energy, natural gas,
and other
commodities allow for opportunities to secure prices in a volatile
energy
market.
|
Business
Operations
Our
regulated and
nonregulated businesses have distinct competencies and business strategies.
They
offer differing energy and energy related products and services, and experience
a wide array of risks and challenges. "Management's
Discussion and Analysis of Financial Condition and Results of Operations
-
Introduction - WPS Resources,"
appearing in our
2005 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 our 2005 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 our
2005 Form 10-K.
The
table below
discloses future natural gas and electric sales volumes under contract at
ESI as
of June 30. Contracts are generally one to three years in duration. ESI
expects that its ultimate sales volumes in 2006 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 6/30/2006
(1)(2)
|
|
07/01/06
to
06/30/07
|
|
07/01/07
to
06/30/08
|
|
After
June 30, 2008
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - billion cubic feet
|
|
|
127.6
|
|
|
22.2
|
|
|
7.0
|
|
Retail
sales
volumes - billion cubic feet
|
|
|
177.3
|
|
|
52.8
|
|
|
43.3
|
|
Total
natural
gas sales volumes
|
|
|
304.9
|
|
|
75.0
|
|
|
50.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - million kilowatt-hours
|
|
|
19,020
|
|
|
7,862
|
|
|
5,732
|
|
Retail
sales
volumes - million kilowatt-hours
|
|
|
2,511
|
|
|
579
|
|
|
316
|
|
Total
electric sales volumes
|
|
|
21,531
|
|
|
8,441
|
|
|
6,048
|
|
(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.
|
(2)
|
The
above
forward contracted volumes do not include volumes related to
Sunbury.
|
For
comparative
purposes, the future natural gas and electric sales volumes under contract
at
June 30, 2005, are shown below. The actual electric and natural gas
sales volumes for the six months ended June 30, 2006, and 2005 are
disclosed within Results
of
Operations - WPS Resources, ESI Segment Operations
below.
Forward
Contracted Volumes at 6/30/2005 (1)(2)
|
|
07/01/05
to
06/30/06
|
|
07/01/06
to
06/30/07
|
|
After
June 30, 2007
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - billion cubic feet
|
|
|
105.6
|
|
|
15.4
|
|
|
0.7
|
|
Retail
sales
volumes - billion cubic feet
|
|
|
138.5
|
|
|
49.5
|
|
|
9.6
|
|
Total
natural
gas sales volumes
|
|
|
244.1
|
|
|
64.9
|
|
|
10.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
sales volumes - million kilowatt-hours
|
|
|
10,008
|
|
|
3,026
|
|
|
1,342
|
|
Retail
sales
volumes - million kilowatt-hours
|
|
|
3,601
|
|
|
1,229
|
|
|
210
|
|
Total
electric sales volumes
|
|
|
13,609
|
|
|
4,255
|
|
|
1,552
|
|
(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.
|
(2)
|
The
above
forward contracted volumes do not include volumes related to
Sunbury.
|
Both
retail and
wholesale natural gas volumes under contract have increased as of June 30,
2006, compared to June 30, 2005. The increase in retail natural gas volumes
under contract was driven by continued customer growth in Canada. Also, ESI
has
been able to lock in contracts with retail natural gas customers in other
markets due in part to a decline in natural gas prices compared to the latter
half of 2005. In the second quarter of 2006, customers were more inclined
to
lock in prices related to their natural gas purchases, compared to the second
quarter of 2005. Increased volatility in natural gas prices and high natural
gas
storage spreads (future natural gas sales prices were higher than the near
term
price of natural gas) increased the profitability of natural gas transactions,
driving the increase in wholesale natural gas sales volumes under contract
at
June 30, 2006, compared to June 30, 2005. Wholesale electric volumes
under contract increased significantly at June 30, 2006. ESI continues to
expand its wholesale origination capabilities with a focus on physical,
customer-based purchase and sale agreements in areas where it has market
expertise. The emphasis ESI is placing on its originated wholesale customer
electric business is producing encouraging results and, as a result, ESI
has
recently entered into numerous contracts to provide electricity to customers
in
the future. Retail electric sales volumes under contract have decreased at
June 30, 2006. ESI has experienced significant customer attrition in
Michigan as a result of tariff changes granted to Michigan utilities and
high
wholesale energy prices. ESI's retail electric aggregation sales in Ohio
ended
on December 31, 2005, with the expiration of ESI's contracts with its Ohio
aggregation customers.
In
order to mitigate its exposure to credit risk, ESI employs credit policies.
As a
result of these credit policies, ESI has not experienced significant write-offs
from its large wholesale counterparties to date. The table below summarizes
ESI's wholesale counterparty credit exposure, categorized by maturity date,
as
of June 30, 2006. At June 30, 2006, ESI had net exposure with two
investment grade counterparties that were more than 10% of total exposure.
Net
exposure with these counterparties was $73.9 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
|
|
$
|
41.6
|
|
$
|
27.3
|
|
$
|
12.1
|
|
$
|
2.2
|
|
Investment
grade - other
|
|
|
108.2
|
|
|
67.8
|
|
|
37.3
|
|
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment
grade - regulated utility
|
|
|
27.9
|
|
|
27.9
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-rated
-
regulated utility (3)
|
|
|
10.7
|
|
|
3.4
|
|
|
6.8
|
|
|
0.5
|
|
Non-rated
-
other (3)
|
|
|
72.3
|
|
|
57.3
|
|
|
13.0
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
$
|
260.7
|
|
$
|
183.7
|
|
$
|
69.2
|
|
$
|
7.8
|
|
(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 $66.8 million
at June 30, 2006, $45.3 million from investment grade
counterparties, and $21.5 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
Second
Quarter 2006 Compared with Second Quarter 2005
WPS Resources
Overview
WPS Resources'
results of operations for the quarters ended June 30 are shown in the
following table:
WPS Resources'
Results
(Millions,
except share amounts)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Income
available for common shareholders
|
|
$
|
34.9
|
|
$
|
23.9
|
|
|
46.0
|
%
|
Basic
earnings per share
|
|
$
|
0.83
|
|
$
|
0.63
|
|
|
31.7
|
%
|
Diluted
earnings per share
|
|
$
|
0.83
|
|
$
|
0.62
|
|
|
33.9
|
%
|
Income
available
for common shareholders was $34.9 million ($0.83 diluted earnings per
share) for the quarter ended June 30, 2006, compared to $23.9 million
($0.62 diluted earnings per share) for the same quarter in 2005. Significant
factors impacting the change in earnings and earnings per share are as follows
(and are discussed in more detail thereafter):
·
|
Electric
utility earnings increased $2.5 million, from $20.9 million for
the quarter ended June 30, 2005, to $23.4 million for the
quarter ended June 30, 2006. The increase in electric utility
earnings was driven by fuel and purchased power costs that were
less than
were recovered in rates in the second quarter of 2006, compared
to no
significant over or under collections in the second quarter of
2005. Fuel
and purchased power costs are expected to be greater than what
will be
recovered in rates in the second half of the year, which should
negatively
impact margins during that period. A retail electric rate increase
at WPSC
also contributed to higher earnings, but the rate increase was
largely
offset by an increase in various operating and maintenance expenses.
|
·
|
The
net loss
from natural gas utility operations increased $5.6 million, from
$1.9 million for the quarter ended June 30, 2005, to
$7.5 million for the quarter ended June 30, 2006. A combined net
loss of $5 million related to the results of operations, including
transition costs, for MGUC (assets acquired on April 1, 2006) and
transition costs incurred by MERC (assets acquired July 1, 2006).
During
the second quarter of 2006, $4.1 million of external pre-tax
transition costs were incurred by these natural gas utilities.
The net
loss recognized at MGUC in excess of transition costs incurred
is
attributable to the seasonal nature of natural gas utility operations.
|
·
|
ESI's
earnings increased $9.8 million, from $3.6 million for the
quarter ended June 30, 2005, to $13.4 million for the quarter
ended June 30, 2006. Higher earnings were driven by a
$22.0 million pre-tax increase in margin and a $9.0 million
pre-tax gain on the sale of ESI's Kimball storage field in the
second
quarter of 2006. These items were partially offset by a $5.4 million
increase in operating and maintenance expenses (related to continued
business expansion), a $2.7 million decrease in Section 29/45K
federal tax credits recognized from ESI's investment in a synthetic
fuel
facility, a $2.3 million pre-tax increase in miscellaneous expense,
and a $0.9 million after-tax increase in the loss from discontinued
operations.
|
·
|
Earnings
at
the Holding Company and Other segment increased $4.3 million, from
$1.3 million for the quarter ended June 30, 2005, to
$5.6 million for the quarter ended June 30, 2006. The increase
was driven by a $6.2 million pre-tax gain recognized from the sale of
our one-third interest in Guardian Pipeline, LLC and a
$3.9 million increase in pre-tax equity earnings from ATC, partially
offset by an increase in interest expense. Pre-tax equity earnings
from
ATC were $9.8 million for the quarter ended June 30, 2006,
compared to $5.9 million for the quarter ended June 30, 2005.
|
·
|
The
change in
diluted earnings per share was impacted by the items discussed
above as
well as an increase of 3.8 million shares (9.9%) in the weighted
average number of outstanding shares of WPS Resources' common stock
for the quarter ended June 30, 2006, compared to the same quarter in
2005. WPS Resources issued 1.9 million shares of common stock
through a public offering in November 2005 and also issued
2.7 million shares of common stock in May 2006 in order to settle its
forward equity agreement with an affiliate of J.P. Morgan Securities,
Inc.
Additional shares were also issued under the Stock Investment Plan
and
certain stock-based employee benefit
plans.
|
Overview
of
Utility Operations
Utility
operations
include (1) the electric utility segment, consisting of the electric operations
of WPSC and UPPCO, and (2) the gas utility segment, consisting of the natural
gas operations of WPSC and MGUC, as well as certain transition costs related
to
the acquisition of Aquila's natural gas distribution operations in Minnesota
by
MERC. Income
available
for common shareholders attributable to the electric utility segment was
$23.4 million for the quarter ended June 30, 2006, compared to
$20.9 million for the same quarter in 2005. The net loss attributable to
the gas utility segment was $7.5 million for the quarter ended
June 30, 2006, compared to a net loss of $1.9 million for the same
quarter in 2005.
Electric
Utility
Segment Operations
WPS Resources'
Electric Utility
|
|
Three
Months
Ended June 30,
|
|
Segment
Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
262.4
|
|
$
|
240.2
|
|
|
9.2
|
%
|
Fuel
and
purchased power costs
|
|
|
118.8
|
|
|
79.2
|
|
|
50.0
|
%
|
Margins
|
|
$
|
143.6
|
|
$
|
161.0
|
|
|
(10.8
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
in
kilowatt-hours
|
|
|
3,777.0
|
|
|
3,803.2
|
|
|
(0.7
|
%)
|
Electric
utility
revenue increased $22.2 million (9.2%) for the quarter ended June 30,
2006, compared to the same quarter in 2005, largely due to an approved annual
electric rate increase for WPSC's Wisconsin retail customers. In
December 2005, the PSCW approved a retail electric rate increase of
$79.9 million (10.1%), effective January 1, 2006. The retail electric rate
increase was required primarily because of higher fuel and purchased power
costs
(including costs associated with the Fox Energy Center power purchase
agreement), costs related to the construction of Weston 4, higher
transmission expenses, and recovery of a portion of the costs related to
the
2005 Kewaunee outage. Partially offsetting the items discussed above, rates
were
lowered to reflect a refund to customers in 2006 of a portion of the proceeds
received from the liquidation of the nonqualified decommissioning trust fund
as
a result of the July 2005 sale of Kewaunee. The increase in electric utility
revenue related to the rate increase was also partially offset by a 0.7%
decrease in overall electric utility sales volumes. Electric utility sales
volumes to residential customers decreased, primarily due to summer weather
conditions during the second quarter of 2006 that were 41% cooler during
the
cooling season, compared to the same quarter in 2005. The decrease in electric
sales volumes to residential customers, however, was substantially offset
by a
4.5% increase in sales volumes to wholesale customers, driven by higher
demand.
The
electric
utility margin decreased $17.4 million (10.8%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005. The decrease in the
electric utility margin was driven by an $18.1 million (12.1%) decrease in
WPSC's electric margin, primarily related to the sale of Kewaunee, and the
related power purchase agreement. Prior to the sale of Kewaunee, only nuclear
fuel expense was reported as a component of fuel, natural gas, and purchased
power. Subsequent to the sale, all payments (both variable payments for energy
delivered and fixed payments) to Dominion Energy Kewaunee, LLC for power
purchased from Kewaunee are reported as a component of utility cost of fuel,
natural gas, and purchased power. As a result of the sale, WPSC no longer
incurs
operating and maintenance expenses, depreciation and decommissioning expense,
or
interest expense related to Kewaunee.
Excluding
the
$24.3 million of fixed payments made to Dominion Energy Kewaunee in the
second quarter of 2006, WPSC's electric utility margin increased
$6.2 million. The increase in electric utility margins was driven by fuel
and purchased power costs that were less than were recovered in rates in
the
second quarter of 2006, compared to no significant over or under collections
in
the second quarter of 2005. Fuel and purchased power costs are expected to
be
greater than what will be recovered in rates in the second half of the year,
which should negatively impact margins during that period. The rate increase
and
higher wholesale electric sales volumes also contributed to the higher margin.
Partially offsetting these increases, margin was negatively impacted by a
decrease in rates related to the refund of a portion of the Kewaunee
nonqualified decommissioning trust fund to customers ($16.2 million of
proceeds received from the liquidation of this fund were refunded to customers
in the second quarter of 2006). Pursuant to regulatory accounting, the decrease
in margin related to this refund was substantially offset by a corresponding
decrease in operating and maintenance expenses as explained below and,
therefore, did not have a significant impact on earnings. The unfavorable
weather conditions during the cooling season (discussed above), also negatively
impacted margin.
Gas
Utility
Segment Operations
WPS Resources'
|
|
Three
Months
Ended June 30,
|
|
Gas
Utility
Segment Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
95.6
|
|
$
|
89.8
|
|
|
6.5
|
%
|
Purchased
gas
costs
|
|
|
62.0
|
|
|
66.2
|
|
|
(6.3
|
%)
|
Margins
|
|
$
|
33.6
|
|
$
|
23.6
|
|
|
42.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
in
therms
|
|
|
194.9
|
|
|
162.5
|
|
|
19.9
|
%
|
Natural
gas utility
revenue increased $5.8 million (6.5%) for the quarter ended June 30,
2006, compared to the same quarter in 2005. Natural gas utility revenue
increased due to the acquisition by MGUC of the natural gas distribution
operations in Michigan on April 1, 2006. MGUC contributed $27.6 million to
natural gas utility revenue and 66.1 million therms to natural gas
throughput volumes for the quarter ended June 30, 2006. WPSC's natural gas
utility revenue was $68.0 million for the quarter ended June 30, 2006,
compared to $89.8 million for the same quarter in the prior year. Lower
natural gas revenues at WPSC were driven by a 20.7% decrease in natural gas
throughput volumes, as a result of an 84.6% decrease in natural gas volumes
sold
to the electric utility and a 7.7% decrease in natural gas volumes sold to
residential, and commercial and industrial customers. The decrease in natural
gas volumes sold to the electric utility was driven by a decrease in the
need
for the electric utility to run its peaker generation units due to weather
that
was 41% cooler during the cooling season in the second quarter of 2006, compared
to the same quarter in 2005, as well as higher dispatch of the peaker generation
units by MISO in 2005 for reliability purposes. The decrease in throughput
volumes to residential, and commercial and industrial customers was primarily
related to weather that was 12% warmer during the heating season in the second
quarter of 2006, compared to the same quarter in 2005. These customers are
also
taking measures to conserve energy as a result of higher natural gas prices.
Partially offsetting these decreases were an increase in the per-unit cost
of
natural gas and a rate increase at WPSC. Natural gas costs were 5.3% higher
(on
a per-unit basis) during the quarter ended June 30, 2006, compared to the
same quarter in 2005. Following regulatory practice, changes in the total
cost
of natural gas are passed on to customers through a purchased gas adjustment
clause, as allowed by the PSCW. In December 2005, the PSCW issued a final
order authorizing an annual natural gas rate increase for WPSC of
$7.2 million (1.1%), effective January 1, 2006. The rate increase was
required as a result of infrastructure improvements necessary to ensure the
reliability of the natural gas distribution system.
The
natural gas
utility margin increased $10.0 million (42.4%) for the quarter ended
June 30, 2006, compared to the quarter ended June 30, 2005. The
margin provided by MGUC was $9.8 million, and WPSC's natural gas utility
margin was relatively flat compared to the second quarter of 2005. At WPSC,
increased margin related to the natural gas rate increase was substantially
offset by a decrease in throughput volumes to higher margin residential,
and
commercial and industrial customers. The decrease in natural gas volumes
sold to
the electric utility did not have a significant impact on WPSC's natural
gas
utility margin as very low margins are recognized on sales to the electric
utility.
Overview
of
ESI Operations
ESI
offers natural
gas, electric, and alternative fuel supplies, as well as energy management
and
consulting services, to retail and wholesale customers in the Midwest and
Northeastern United States, Texas, and adjacent portions of Canada. ESI also
owns several merchant electric generation plants, primarily in the Midwest
and
Northeastern United States and adjacent portions of Canada.
Prior
to the fourth
quarter of 2005, WPS Resources reported two nonregulated segments, ESI and
WPS Power Development. Effective in the fourth quarter of 2005,
WPS Resources began reporting one nonregulated segment, ESI. Segment
information related to prior periods reflects this change.
Income
available
for common shareholders attributable to ESI was $13.4 million for the
quarter ended June 30, 2006, compared to $3.6 million for the same
period in 2005.
|
|
Three
Months
Ended June 30,
|
|
(Millions
except natural gas sales volumes)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
revenues
|
|
$
|
1,134.1
|
|
$
|
995.3
|
|
|
13.9
|
%
|
Nonregulated
cost of fuel, natural gas, and purchased power
|
|
|
1,078.2
|
|
|
961.4
|
|
|
12.1
|
%
|
Margins
|
|
$
|
55.9
|
|
$
|
33.9
|
|
|
64.9
|
%
|
Margin
Detail
|
|
|
|
|
|
|
|
|
|
|
Electric
and
other margins
|
|
$
|
41.7
|
|
$
|
20.5
|
|
|
103.4
|
%
|
Natural
gas
margins
|
|
$
|
14.2
|
|
$
|
13.4
|
|
|
6.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Gross
volumes (includes volumes both physically delivered and net
settled)
|
|
|
|
|
|
|
|
|
|
|
Wholesale
electric sales volumes in kilowatt-hours
|
|
|
12,275.8
|
|
|
10,522.0
|
|
|
16.7
|
%
|
Retail
electric sales volumes in kilowatt-hours
|
|
|
1,304.8
|
|
|
2,009.2
|
|
|
(35.1
|
%)
|
Wholesale
natural gas sales volumes in billion cubic feet
|
|
|
73.9
|
|
|
61.2
|
|
|
20.8
|
%
|
Retail
natural gas sales volumes in billion cubic feet
|
|
|
92.2
|
|
|
78.5
|
|
|
17.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Physical
volumes (includes only transactions settled physically for the
periods
shown)
|
|
|
|
|
|
|
|
|
|
|
Wholesale
electric sales volumes in kilowatt-hours
|
|
|
269.4
|
|
|
462.6
|
|
|
(41.8
|
%)
|
Retail
electric sales volumes in kilowatt-hours
|
|
|
1,035.2
|
|
|
1,641.2
|
|
|
(36.9
|
%)
|
Wholesale
natural gas sales volumes in billion cubic feet
|
|
|
68.1
|
|
|
58.0
|
|
|
17.4
|
%
|
Retail
natural gas sales volumes in billion cubic feet
|
|
|
75.7
|
|
|
65.4
|
|
|
15.7
|
%
|
ESI's
revenue
increased $138.8 million (13.9%) for the quarter ended June 30, 2006,
compared to the same quarter in 2005, driven by increased natural gas prices,
and higher retail and wholesale natural gas volumes.
ESI's
margin
increased $22.0 million (64.9%), from $33.9 million for the quarter
ended June 30, 2005, to $55.9 million for the quarter ended
June 30, 2006. The strong performance of ESI's wholesale electric
operations is continuing in 2006. ESI's wholesale natural gas operations
benefited from volatile natural gas prices. Many other items also contributed
to
the year-over-year net increase in margin and, as a result, a table has been
provided to summarize significant changes. Variances included under "Other
significant items" in the table below are generally related to the timing
of
gain and loss recognition on certain transactions and gains and losses that
do
not frequently occur in ESI's business. All variances depicted in the table
are
discussed in more detail below.
(Millions)
|
|
Increase
(Decrease)
in Margin for the Quarter Ended June 30, 2006 Compared
to Quarter Ended
June 30, 2005
|
|
|
|
|
|
Electric
and other margins
|
|
|
|
Realized
and
unrealized gains on structured origination contracts
|
|
$
|
1.4
|
|
Retail
electric operations
|
|
|
(0.5
|
)
|
Other
wholesale electric operations
|
|
|
8.6
|
|
|
|
|
|
|
Other
significant items:
|
|
|
|
|
Oil
option
activity, net
|
|
|
13.2
|
|
Increased
costs related to the liquidation of an electric supply contract
in
2005
|
|
|
(1.5
|
)
|
|
|
|
|
|
Net
increase
in electric and other margins
|
|
$
|
21.2
|
|
|
|
|
|
|
Natural
gas
margins
|
|
|
|
|
Realized
natural gas margins (primarily wholesale)
|
|
$
|
5.4
|
|
|
|
|
|
|
Other
significant items:
|
|
|
|
|
Spot
to
forward differential
|
|
|
3.3
|
|
Unrealized
gain on Ohio mass market options
|
|
|
1.4
|
|
Other
mark-to-market activity
|
|
|
(9.3
|
)
|
|
|
|
|
|
Net
increase
in natural gas margins
|
|
$
|
0.8
|
|
|
|
|
|
|
Total
increase
in ESI's margin
|
|
$
|
22.0
|
|
ESI's
electric and
other margins increased $21.2 million (103.4%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005. The following
items were the most significant contributors to the net change in ESI's electric
and other margins:
·
|
Realized
and unrealized gains on structured origination contracts
- ESI's
electric and other margin increased $1.4 million in the second
quarter of 2006, compared to the same quarter in 2005, due to realized
and
unrealized gains from origination contracts involving the sale
of energy
through structured transactions to wholesale customers in the northeastern
United States. These origination contracts were not in place in
the second
quarter of 2005. ESI continues to expand its wholesale origination
capabilities with a focus on physical, customer-based purchase
and sale
agreements in areas where it has market expertise.
|
·
|
Retail
electric operations
- The margin
from retail electric operations decreased $0.5 million. A combined
$3.0 million decrease in margin from retail electric operations in
Ohio and northern Maine was substantially offset by a $2.3 million
increase in margin from retail electric operations in Michigan
and
Illinois. ESI's retail electric aggregation sales in Ohio ended
on
December 31, 2005, with the expiration of ESI's contracts with Ohio
aggregation customers. ESI remains prepared to offer future retail
electric service in Ohio as the regulatory climate and market conditions
allow. The decrease in margin from retail electric operations in
northern
Maine was driven by higher supply costs tied to rising diesel fuel
prices.
A portion of the electricity purchased by ESI to supply customers
in
northern Maine is derived from burning wood chips. The cost to
transport
wood chips as well as the operating costs of the machine utilized
to make
the wood chips are negatively impacted by rising diesel fuel prices.
ESI
shares in this diesel fuel exposure with the generation supplier.
The
increase in margin from retail electric operations in Michigan
was driven
by the elimination of the SECA effective March 31, 2006. See "Other
Future Considerations" for more information on ESI's retail electric
operations in Michigan. ESI began offering retail electric products
to
large commercial and industrial customers in Illinois in 2006.
In 2005,
ESI was only offering natural gas products and energy management
services
to customers in Illinois.
|
·
|
Other
wholesale electric operations
- An
$8.6 million increase in margin from other wholesale electric
operations was driven by an increase in net realized and unrealized
gains
related to trading activities utilized to optimize the value of
ESI's
merchant generation fleet and customer supply portfolios. As part
of its
trading activities, ESI seeks to generate profits from the volatility
of
the price of electricity, by purchasing or selling various financial
and
physical instruments (such as forward contracts, options, financial
transmission rights, and capacity contracts) in established wholesale
markets (primarily in the northeastern portion of the United States
where
ESI has market expertise), under risk management policies set by
management and approved by WPS Resources' Board of Directors. ESI
also seeks to maximize the value of its generation and customer
supply
portfolios to reduce market price risk and extract additional value
from
these assets through the use of various financial and physical
instruments
(such as forward contracts, options, financial transmission rights,
and
capacity contracts). Period-by-period variability in the margin
contributed by ESI's optimization strategies and trading activities
is
expected due to constantly changing market conditions. ESI continues
to
produce strong results from its optimization and trading activities
and
believes it maintains a relatively low risk profile. A diverse
mix of
products and markets, combined with disciplined execution and exit
strategies have allowed ESI to consistently generate economic value
and
earnings while staying within WPS Resources' Board of Directors'
authorized value-at-risk (VaR) limits. For more information on
VaR, see
"Item 3, Quantitative and Qualitative Disclosures about Market
Risk."
|
·
|
Oil
option
activity, net
- An
increase in mark-to-market gains on derivative instruments utilized
to
protect the value of a portion of ESI's Section 29/45K federal
tax credits
in 2006 and 2007 contributed $13.2 million to the increase in its
electric and other margin. The derivative instruments have not
been
designated as hedging instruments and, as a result, changes in
the fair
value are recorded currently in earnings. The benefit from Section
29/45K
federal tax credits during a period is primarily based upon estimated
annual synthetic fuel production levels, annual taxable earnings
projections, and any impact projected annual oil prices may have on
the realization of Section 29/45K federal tax credits. This results
in
mark-to-market gains or losses being recognized in different periods,
compared to any tax credit phase-outs that may be recognized. For
more information on Section 29/45K federal tax credits, see Note 11
to the Condensed Notes to Financial Statements, "Commitments and
Contingencies."
|
·
|
Increased
costs related to the liquidation of an electric supply contract
in
2005
- In the
fourth quarter of 2005, an electricity supplier exiting the wholesale
market in Maine requested that ESI liquidate a firm contract to
buy power
in 2006 and 2007. At that time, ESI recognized an $8.2 million gain
related to the liquidation of the contract and entered into a new
contract
with another supplier for firm power in 2006 and 2007 to supply
its
customers in Maine. The cost to purchase power under the new contract
is
more than the cost under the liquidated contract. As a result of
the
termination of this contract, purchased power costs to serve customers
in
Maine will be $6.4 million higher for the year ended
December 31, 2006, and slightly higher than the original contracted
amount in 2007. The liquidation of this contract had a $1.5 million
negative impact on the electric and other margin in the second
quarter of
2006, resulting from higher purchased power costs recorded under
the new
contract.
|
The
natural gas
margin at ESI increased $0.8 million (6.0%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005. The following
items were the most significant contributors to the change in ESI's natural
gas
margin:
·
|
Realized
natural gas margins (primarily wholesale)
-
Realized
natural gas margins increased $5.4 million in the second quarter of
2006, compared to the same quarter in the prior year. The majority
of this
increase was driven by an increase in structured wholesale natural
gas
transactions related to an increase in the volatility of the price
of
natural gas. ESI also realized margin from the withdrawal of natural
gas
from its Kimball storage field in the second quarter of 2006. ESI
was
required to withdraw a certain quantity of natural gas from Kimball
prior
to the sale of the facility, which was completed in the second
quarter of
2006. The average price of natural gas stored in the Kimball facility
was
less than the hedged price at the time of withdrawal. See Note
5 to the
Condensed Notes to Financial Statements, "Acquisitions
and Sales of Assets,"
for more
information on the Kimball sale.
|
·
|
Spot
to
forward differential -
The natural
gas storage cycle had a $3.3 million positive quarter over quarter
impact on ESI's margin. For the quarter ended June 30, 2006, the
natural gas storage cycle had a $0.4 million positive impact on ESI's
natural gas margin, compared to a $2.9 million negative impact on
margin for the second quarter of 2005. At June 30, 2006, there was a
$4.5 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 2006/2007 natural gas storage cycle. This
$4.5 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 2006/2007 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.
|
·
|
Unrealized
gain on Ohio mass market options -
Options
utilized to manage supply costs for Ohio mass market customers,
which were
purchased in the latter half of 2005 and expire in varying months
through
September 2006, had a $1.4 million positive quarter over quarter
impact on ESI's natural gas margin. For the quarter ended June 30,
2006, these options had a $0.6 million positive impact on ESI's
natural gas margin, compared to a $0.8 million negative impact on
margin in the second quarter of 2005. These contracts are utilized
to
reduce the risk of price movements and changes in consumer consumption
patterns. Earnings volatility results from the application of derivative
accounting rules to the options (requiring that these derivative
instruments be marked-to-market), without a corresponding mark-to-market
offset related to the customer contracts. Full requirements natural
gas
contracts with ESI's customers are not considered derivatives and,
therefore, no gain or loss is recognized on these contracts until
settlement.
|
·
|
Other
mark-to-market activity
-
Mark-to-market
losses on derivatives not previously discussed totaling $6.1 million
were recognized in the second quarter of 2006, compared to the
recognition
of $3.2 million of mark-to-market gains on other derivative
instruments in the second quarter of 2005. A significant portion
of the
difference related to changes in the fair market value of derivatives
utilized to mitigate market price risk associated with certain
natural gas
contracts. Earnings volatility results from the application of
derivative
accounting rules (requiring that these derivative instruments be
marked-to-market), without a corresponding mark-to-market offset
related
to the physical natural gas transportation contracts (as these
contracts
are not considered derivative instruments). Therefore, no gain
or loss is
recognized on the physical contracts until
settlement.
|
Overview
of
Holding Company and Other Segment Operations
Holding
Company and
Other operations include the operations of WPS Resources and the nonutility
activities at WPSC, MGUC and UPPCO. Holding Company and Other operations
recognized earnings of $5.6 million during the quarter ended June 30,
2006, compared to earnings of $1.3 million during the same quarter in 2005.
The increase was driven by a $6.2 million pre-tax gain recognized from the
sale of the company's one-third interest in Guardian Pipeline, LLC and
a $3.9 million increase in pre-tax equity earnings from ATC, partially
offset by an increase in interest expense. Pre-tax equity earnings from ATC
were
$9.8 million for the quarter ended June 30, 2006, compared to
$5.9 million for the quarter ended June 30, 2005.
Operating
Expenses
|
|
Three
Months
Ended June 30,
|
|
WPS Resources'
Operating Expenses (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
127.2
|
|
$
|
133.8
|
|
|
(4.9
|
%)
|
Depreciation
and decommissioning expense
|
|
|
25.6
|
|
|
66.6
|
|
|
(61.6
|
%)
|
Taxes
other
than income
|
|
|
14.0
|
|
|
11.9
|
|
|
17.6
|
%
|
Operating
and
Maintenance Expense
Operating
and
maintenances expense decreased $6.6 million (4.9%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005. Utility operating and
maintenance expenses decreased $3.6 million (3.3%), driven by a
$19.1 million decrease in operating and maintenance expenses at
WPSC,
substantially
offset by $14.2 million of operating and maintenance expenses incurred
during the second quarter of 2006 by MGUC (assets acquired on April 1, 2006)
and
by MERC (assets acquired on July 1, 2006) and also by a $1.3 million
increase in operating and maintenance expenses at UPPCO. Of the
$14.2 million of operating and maintenance expenses incurred by MGUC and
MERC, $4.1 million related to external transition costs, primarily for the
start-up of outsourcing activities and other legal and consulting fees.
WPS Resources is outsourcing certain customer functions of MGUC and MERC to
a third-party vendor. All operating and maintenance expenses incurred by
MERC in
the second quarter of 2006 related to these transition costs. The increase
in
UPPCO's operating and maintenance expenses was driven by higher customer
write-offs and benefit costs. The following items were the most significant
contributors to the change in operating and maintenance expenses at
WPSC:
·
|
WPSC
refunded
$16.2 million of the proceeds received from the liquidation of the
Kewaunee nonqualified decommissioning trust fund to ratepayers
in the
second quarter of 2006. This reduction in revenue was offset by
a related
decrease in operating expenses, due to the partial amortization
of the
regulatory liability recorded for the refund of these proceeds.
|
·
|
Operating
and
maintenance expenses related to the Kewaunee nuclear plant decreased
approximately $10 million due to the sale of this facility in July
2005. The decrease in operating and maintenance expenses related
to
Kewaunee did not have a significant impact on net income as WPSC
is still
purchasing power from this facility in the same amount as its original
ownership interest. The cost of the purchased power is included
as a
component of utility cost of fuel, natural gas, and purchased power.
|
·
|
Excluding
Kewaunee, maintenance expenses at WPSC increased $2.0 million in the
second quarter of 2006, compared to the second quarter of 2005.
Planned
maintenance was required on certain combustion turbines in the
second
quarter of 2006, and maintenance expense related to electric distribution
assets also increased.
|
·
|
Customer
account expenses increased $1.3 million, driven by an increase in
consulting fees related to the implementation of a new software
system.
|
Operating
and
maintenance expenses at ESI decreased $3.6 million, driven by a
$9.0 million pre-tax gain recognized on the sale of ESI's Kimball storage
field in the second quarter of 2006. This gain was partially offset by higher
payroll and benefit costs related to ESI's continued business
expansion.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $41.0 million (61.6%) for the quarter
ended June 30, 2006, compared to the quarter ended June 30, 2005,
driven by approximately $38 million of decommissioning expense that was
recorded in the second quarter of 2005, compared to no decommissioning expense
recorded in 2006, and a $4.8 million decrease in depreciation expense
resulting from the sale of Kewaunee in July 2005. Subsequent to the sale
of
Kewaunee, decommissioning expense is no longer recorded. In the second quarter
of 2005, realized gains on decommissioning trust assets recorded in
miscellaneous income were substantially offset by decommissioning expense
pursuant to regulatory practice (see analysis of "Other
Income
(Expense)"
below).
Depreciation expense of $1.8 million was recorded at MGUC during the second
quarter of 2006, partially offsetting the decreases discussed above.
Taxes
Other
Than Income
Taxes
other than
income increased $2.1 million (17.6%), primarily due to a $1.0 million
increase in gross receipts taxes paid by WPSC and $1.0 million of other
taxes recorded by MGUC, primarily related to property taxes.
Other
Income (Expense)
|
|
Three
Months
Ended June 30,
|
|
WPS Resources'
Other Income (Expense) (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
$
|
14.4
|
|
$
|
45.5
|
|
|
(68.4
|
%)
|
Interest
expense
|
|
|
(22.2
|
)
|
|
(15.2
|
)
|
|
46.1
|
%
|
Minority
interest
|
|
|
1.2
|
|
|
1.2
|
|
|
-
|
|
Other
(expense) income
|
|
|
($6.6
|
)
|
$
|
31.5
|
|
|
-
|
|
Miscellaneous
Income
Miscellaneous
income decreased $31.1 million (68.4%) for the quarter ended
June 30, 2006, compared to the quarter ended June 30, 2005. The
decrease in miscellaneous income was driven by $38 million of realized
gains on nuclear decommissioning trust assets, which was recorded in the
second
quarter of 2005. Pursuant to regulatory practice, the increase in miscellaneous
income related to the 2005 realized gains was substantially offset by an
increase in decommissioning expense in 2005. Miscellaneous income was also
negatively impacted as ESI's share of operating losses related to its equity
method investment in a synthetic fuel facility increased $4.0 million in
the second quarter of 2006, compared to the same period in 2005. In the second
quarter of 2006, ESI elected to take more production than it had taken in
the
second quarter of 2005. This opportunity presented itself after ESI's partners
in this facility began curtailing their production in the second quarter
of
2006. See Note 11 "Commitments
and
Contingencies,"
for more
information related to ESI's investment in the synthetic fuel facility. The
decreases in decommissioning trust earnings and increase in operating losses
related to the synthetic fuel facility were partially offset by a
$6.2 million pre-tax gain recognized from the sale of the company's
one-third interest in Guardian Pipeline, LLC and a $3.9 million
increase in pre-tax equity earnings from ATC.
Interest
Expense
Interest
expense
increased $7.0 million (46.1%) for the quarter ended June 30, 2006,
compared to the same period in 2005, due primarily to an increase in the
average
amount of short-term debt outstanding and higher borrowing costs. In the
second
quarter of 2006, short-term debt was primarily utilized to purchase the natural
gas distribution operations in Michigan, fund the construction of Weston 4,
and for working capital requirements at ESI.
Provision
for Income Taxes
The
effective tax
rate was 31.3% for the quarter ended June 30, 2006, compared to 20.3% for
the quarter ended June 30, 2005. The increase in the effective tax rate was
driven by an increase in income before taxes combined with a decrease in
Section 29/45K federal tax credits recognized in the second quarter of
2006, compared to the same quarter in 2005. Our
ownership
interest in a synthetic fuel operation, along with the procurement of additional
tons of synthetic fuel from our partners in this operation in the second
quarter
of 2006, resulted in recognizing the tax benefit of Section 29/45K federal
tax credits totaling $3.1 million in the second quarter of 2006, compared
to $5.8 million in the second quarter of 2005. The decrease in Section
29/45K federal tax credits recognized was driven by the impact high oil prices
may have on our ability to realize the benefit of Section 29/45K federal
tax credits, partially offset by the Section 29/45K federal tax credits
recognized on the additional production that was procured.
At
June 30, 2006, based upon estimated annual average oil prices, we
anticipate that approximately 76% of the 2006 tax credits that otherwise
would
be available from the production and sale of synthetic fuel would be phased-out.
WPS Resources estimates that at June 30, 2006, an additional
$12 million of tax credits would have been recognized related to its
ownership interest in the synthetic fuel operation (including the additional
tons procured) in the second quarter of 2006 absent the projected tax credit
phase-out.
For
the year ending
December 31, 2006, including the projected phase-out, we expect to
recognize the benefit of Section 29/45K federal tax credits totaling
approximately $9 million, excluding the impact of hedging strategies. If no
phase-out occurs, then we would expect to recognize approximately
$35 million of tax credits in 2006; however, based upon current
legislation, oil prices would have to drop considerably during the remainder
of
the year to avoid any phase-out. For the year ended December 31, 2005, we
recognized the benefit of Section 29/45K federal tax credits totaling
$26.1 million. See Note 11 "Commitments
and
Contingencies,"
for more
information related to Section 29/45K federal tax credits.
Discontinued
Operations
The
loss from
discontinued operations (Sunbury) increased $0.9 million, from
$4.7 million for the quarter ended June 30, 2005, to $5.6 million
for the quarter ended June 30, 2006. The increased loss was driven by a
$5.0 million ($3.0 million after-tax) decrease in gross margin, a
$6.9 million ($4.1 million after-tax) increase in operating and
maintenance expenses, partially offset by a $9.2 million ($5.5 million
after-tax) decrease in interest expense. While production increased in the
second quarter of 2006, compared to the same period in 2005, gross margin
decreased as a result of the higher cost of fuel and emission allowances.
Since
the sale of its allocated emission allowances in the second quarter of 2005,
Sunbury must purchase emission allowances required for operation at market
prices. In the second quarter of 2005, Sunbury recognized a pre-tax gain
of
$85.9 million from the sale of its allocated emission allowances, which was
substantially offset by an impairment loss of $80.6 million related to the
Sunbury plant. The net $5.3 million pre-tax gain resulting from these items
in the second quarter of 2005 drove the period-over-period increase in operating
and maintenance expenses. The decrease in interest expense was driven by
$9.1 million of interest expense recognized in the second quarter of 2005
related to the termination of an interest rate swap pertaining to Sunbury's
non-recourse debt obligation. The restructuring of the Sunbury debt to a
WPS Resources obligation in June 2005 triggered the recognition of
interest expense equivalent to the mark-to-market value of the swap at the
date
of restructuring.
Six
Months
2006 Compared with Six Months 2005
WPS Resources
Overview
WPS Resources'
results of operations for the six months ended June 30 are shown in the
following table:
WPS Resources'
Results
(Millions,
except share amounts)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Income
available for common shareholders
|
|
$
|
95.0
|
|
$
|
89.8
|
|
|
5.8
|
%
|
Basic
earnings per share
|
|
$
|
2.31
|
|
$
|
2.37
|
|
|
(2.5
|
%)
|
Diluted
earnings per share
|
|
$
|
2.30
|
|
$
|
2.35
|
|
|
(2.1
|
%)
|
Income
available
for common shareholders was $95.0 million ($2.30 diluted earnings per
share) for the six months ended June 30, 2006, compared to
$89.8 million ($2.35 diluted earnings per share) for the same period in
2005. Significant factors impacting the change in earnings and earnings per
share are as follows (and are discussed in more detail thereafter):
·
|
Electric
utility earnings decreased $5.5 million, from $44.4 million for
the six months ended June 30, 2005, to $38.9 million for
the six months ended June 30, 2006. The decrease in electric utility
earnings was driven by the negative impact unfavorable weather
conditions
and residential customer conservation efforts had on margin, as
well as an
increase in various operating expenses. These items were partially
offset
by the positive impact of fuel and purchased power costs that were
less
than were recovered in rates during the six months ended June 30,
2006, compared to no significant over or under collections during
the six
months ended June 30, 2005. Fuel and purchased power costs are
expected to
be greater than what will be recovered in the second half of the
year,
which should negatively impact margin during that period. The retail
electric rate increase and higher wholesale electric sales volumes
also
had a positive impact on electric utility earnings.
|
·
|
Results
from
natural gas utility operations decreased $12.9 million, from earnings
of $12.1 million for the six months ended June 30, 2005, to
a net loss of $0.8 million for the six months ended June 30,
2006. A combined net loss of $9 million related to the results of
operations, including transition costs, for MGUC and transition
costs
incurred by MERC. During the six months ended June 30, 2006,
$8.2 million of external pre-tax transition costs were incurred by
these natural gas utilities. The net loss recognized by MGUC in
excess of
transition costs incurred is attributable to the seasonal nature
of
natural gas utility operations. Net income recognized from natural
gas
utility operations at WPSC decreased $3.7 million (30.3%), driven
primarily by a decrease in margin resulting from lower throughput
volumes
as a result of warmer weather during the heating season, customer
conservation efforts, and an increase in operating and maintenance
expenses.
|
·
|
ESI's
earnings increased $18.7 million, from $31.8 million for the six
months ended June 30, 2005, to $50.5 million for the same period
in 2006. Higher earnings were driven by a $60.9 million pre-tax
increase in margin, partially offset by an $11.0 million decrease in
Section 29/45K federal tax credits recognized from ESI's investment
in a
synthetic fuel facility, a $3.9 million after-tax increase in the
loss from discontinued operations, and a $4.1 million pre-tax
increase in miscellaneous expense.
|
·
|
Earnings
at
the Holding Company and Other segment increased $4.9 million, from
$1.5 million for the six months ended June 30, 2005, to
$6.4 million for the six months ended June 30, 2006. The
increase was primarily related to a $7.6 million increase in pre-tax
equity earnings from ATC and a $6.2 million pre-tax gain recognized
from the sale of our one-third interest in
Guardian Pipeline, LLC, partially offset by a $3.7 million
pre-tax increase in operating and maintenance expenses and an increase
in
interest expense. Pre-tax equity earnings from ATC were $18.7 million
for the six months ended June 30, 2006, compared to
$11.1 million for the six months ended June 30, 2005.
|
·
|
The
change in
diluted earnings per share was impacted by the items discussed
above as
well as an increase of 3.1 million shares (8.1%) in the weighted
average number of outstanding shares of WPS Resources' common stock
for the six months ended June 30, 2006, compared to the same period
in 2005. WPS Resources issued 1.9 million shares of common stock
through a public offering in November 2005 and also issued
2.7 million shares of common stock in May 2006 in order to settle its
forward equity agreement with an affiliate of J.P. Morgan Securities,
Inc.
Additional shares were also issued under the Stock Investment Plan
and
certain stock-based employee benefit
plans.
|
Overview
of
Utility Operations
Income
available
for common shareholders attributable to the electric utility segment was
$38.9 million for the six months ended June 30, 2006, compared to
$44.4 million for the same period in 2005. The net loss attributable to the
gas utility segment was $0.8 million for the six months ended
June 30, 2006, compared to net income available for common shareholders of
$12.1 million for the six months ended
June 30, 2005.
Electric
Utility Segment Operations
WPS Resources'
Electric Utility
|
|
Six
Months
Ended June 30,
|
|
Segment
Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
518.8
|
|
$
|
484.2
|
|
|
7.1
|
%
|
Fuel
and
purchased power costs
|
|
|
244.5
|
|
|
159.9
|
|
|
52.9
|
%
|
Margins
|
|
$
|
274.3
|
|
$
|
324.3
|
|
|
(15.4
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
in
kilowatt-hours
|
|
|
7,606.3
|
|
|
7,483.7
|
|
|
1.6
|
%
|
Electric
utility
revenue increased $34.6 million (7.1%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005, largely
due to an approved annual electric rate increase for WPSC's Wisconsin retail
customers (discussed above). Electric sales volumes also increased 1.6%,
primarily related to a 12.0% increase in sales volumes to wholesale customers
due to higher demand, largely offset by a decrease in sales volumes to
residential customers, driven primarily by unfavorable weather conditions
during
both the heating and cooling seasons in the first half of 2006, compared
to the
same
period in 2005, and customer conservation efforts resulting from recent rate
increases. For the six months ended June 30, 2006, weather during the
heating season was 11% warmer and weather during the cooling season was 41%
cooler, compared to the same period in 2005.
The
electric
utility margin decreased $50.0 million (15.4%) for the six months ended
June 30, 2006, compared to the same period in 2005. The decrease in
electric margin was driven by a $51.6 million (17.2%) decrease in WPSC's
electric margin, primarily related to the sale of Kewaunee on July 5, 2005,
and
the related power purchase agreement. Excluding the $48.3 million of fixed
payments made to Dominion Energy Kewaunee during the first six months of
2006,
WPSC's electric utility margin decreased $3.3 million. The margin was
negatively impacted by a decrease in rates related to the refund of a portion
of
the Kewaunee nonqualified decommissioning trust fund to customers
($30.0 million of proceeds received from the liquidation of this fund were
refunded to customers during the six months ended June 30, 2006). Pursuant
to regulatory accounting, the decrease in margin related to this refund was
substantially offset by a corresponding decrease in operating and maintenance
expenses as explained below and, therefore, did not have a significant impact
on
earnings. The unfavorable weather conditions during both the heating and
cooling
seasons, as well as residential customer conservation efforts also negatively
impacted margin. These items were partially offset by the positive impact
of
fuel and purchased power costs that were less than were recovered in rates
during the six months ended June 30, 2006, compared to no significant over
or under collections during the six months ended June 30, 2005. Fuel and
purchased power costs are expected to be greater than what will be recovered
in
the second half of the year, which should negatively impact margin during
that
period. The rate increase and higher wholesale electric sales volumes also
had a
positive impact on margin. The rate increase was necessary to recover increases
in fuel as well as increases in various operating and maintenance expenses,
which are discussed below.
Gas
Utility
Segment Operations
WPS Resources'
|
|
Six
Months
Ended June 30,
|
|
Gas
Utility
Segment Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
288.6
|
|
$
|
264.4
|
|
|
9.2
|
%
|
Purchased
gas
costs
|
|
|
210.2
|
|
|
194.5
|
|
|
8.1
|
%
|
Margins
|
|
$
|
78.4
|
|
$
|
69.9
|
|
|
12.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
in
therms
|
|
|
461.8
|
|
|
471.3
|
|
|
(2.0
|
%)
|
Natural
gas utility
revenue increased $24.2 million (9.2%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005,
driven by the acquisition of natural gas distribution
operations
in
Michigan in the second quarter of 2006. The natural gas distribution operations
in Michigan, which were acquired on April 1, 2006, contributed
$27.6 million to natural gas utility revenue and 66.1 million therms
to natural gas throughput volumes during the six months ended June 30,
2006. WPSC's natural gas utility revenue was $261.0 million for the six
months ended June 30, 2006, compared to $264.4 million for the same
period in the prior year. Lower natural gas revenues at WPSC were driven
by a
16.0% decrease in natural gas throughput volumes, primarily related to a
77.1%
decrease in natural gas volumes sold to the electric utility (resulting from
a
decrease in the need for the electric utility to run its peaker generation
units
due to weather that was 41% cooler during the cooling season in the six months
ended June 30, 2006, compared to the same period in 2005 as well as higher
dispatch of the peaker generation units by MISO in 2005 for reliability
purposes), and also by an 11.2% decrease in throughput volumes to residential
and commercial and industrial customers due to weather that was 11% warmer
during the heating season in first half of 2006, compared to the same period
in
the prior year, and also due to customer conservation efforts. Customers
are
taking measures to conserve energy as a result of the high natural gas prices.
Partially offsetting these decreases was an increase in the per-unit cost
of
natural gas and the rate increase at WPSC. Natural gas costs were 26.8% higher
(on a per-unit basis) during the six months ended June 30, 2006, compared
to the same period in 2005.
The
natural gas
utility margin increased $8.5 million (12.2%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005.
The margin provided by MGUC was $9.8 million, while WPSC's natural gas
utility margin decreased $1.3 million. At WPSC, a decrease in throughput
volumes to higher margin residential, and commercial and industrial customers
(discussed above) was partially offset by the rate increase. The decrease
in
throughput volumes to the electric utility did not have a significant impact
on
WPSC's natural gas utility margin as very low margins are recognized on sales
to
the electric utility.
Overview
of
ESI Operations
Income
available
for common shareholders attributable to ESI was $50.5 million for the six
months ended June 30, 2006, compared to $31.8 million for the six
months ended June 30, 2005.
|
|
Six
Months
Ended June 30,
|
|
(Millions
except natural gas sales volumes)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Nonregulated
revenues
|
|
$
|
2,697.3
|
|
$
|
2,047.6
|
|
|
31.7
|
%
|
Nonregulated
cost of fuel, natural gas, and purchased power
|
|
|
2,559.9
|
|
|
1,971.1
|
|
|
29.9
|
%
|
Margins
|
|
$
|
137.4
|
|
$
|
76.5
|
|
|
79.6
|
%
|
Margin
Detail
|
|
|
|
|
|
|
|
|
|
|
Electric
and
other margins
|
|
$
|
84.9
|
|
$
|
42.9
|
|
|
97.9
|
%
|
Natural
gas
margins
|
|
$
|
52.5
|
|
$
|
33.6
|
|
|
56.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Gross
volumes (includes volumes both physically delivered and net
settled)
|
|
|
|
|
|
|
|
|
|
|
Wholesale
electric sales volumes in kilowatt-hours
|
|
|
26,584.5
|
|
|
19,092.3
|
|
|
39.2
|
%
|
Retail
electric sales volumes in kilowatt-hours
|
|
|
2,514.2
|
|
|
4,056.2
|
|
|
(38.0
|
%)
|
Wholesale
natural gas sales volumes in billion cubic feet
|
|
|
153.7
|
|
|
122.0
|
|
|
26.0
|
%
|
Retail
natural gas sales volumes in billion cubic feet
|
|
|
192.5
|
|
|
169.0
|
|
|
13.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Physical
volumes (includes only transactions
settled
physically for the periods shown)
|
|
|
|
|
|
|
|
|
|
|
Wholesale
electric sales volumes in kilowatt-hours
|
|
|
1,050.7
|
|
|
1,452.9
|
|
|
(27.7
|
%)
|
Retail
electric sales volumes in kilowatt-hours
|
|
|
2,037.1
|
|
|
3,395.7
|
|
|
(40.0
|
%)
|
Wholesale
natural gas sales volumes in billion cubic feet
|
|
|
142.3
|
|
|
115.9
|
|
|
22.8
|
%
|
Retail
natural gas sales volumes in billion cubic feet
|
|
|
171.8
|
|
|
143.2
|
|
|
20.0
|
%
|
ESI's
revenues
increased $649.7 million (31.7%) for the six months ended June 30,
2006, compared to the same period in 2005, primarily driven by increased
natural
gas prices, and higher retail and wholesale natural gas volumes.
ESI's
margin
increased $60.9 million (79.6%), from $76.5 million for the six months
ended June 30, 2005, to $137.4 million for the six months ended
June 30, 2006. The strong performance of ESI's wholesale electric
operations in 2005 is continuing in 2006. ESI's wholesale natural gas operations
benefited from volatile natural gas prices and high natural gas storage spreads
(future natural gas sales prices were higher than the near term price of
natural
gas) in the first half of 2006. Many other items also contributed to the
year-over-year net increase in margin and, as a result, a table has been
provided to summarize significant changes. Variances included under "Other
significant items" in the table below are generally related to the timing
of
gain and loss recognition on certain transactions and gains and losses that
do
not frequently occur in ESI's business. All variances depicted in the table
are
discussed in more detail below.
(Millions)
|
|
Increase
(Decrease)
in Margin for the Six Months Ended June 30, 2006 Compared to Six
Months Ended
June 30, 2005
|
|
|
|
|
|
Electric
and other margins
|
|
|
|
Realized
and
unrealized gains on structured origination contracts
|
|
$
|
6.7
|
|
Retail
electric operations
|
|
|
(10.7
|
)
|
Other
wholesale electric operations
|
|
|
26.9
|
|
|
|
|
|
|
Other
significant items:
|
|
|
|
|
Oil
option
activity, net
|
|
|
20.8
|
|
Unrealized
gains on non-qualifying hedges
|
|
|
2.0
|
|
Increased
costs related to the liquidation of an electric supply contract
in
2005
|
|
|
(3.7
|
)
|
Net
increase
in electric and other margins
|
|
$
|
42.0
|
|
|
|
|
|
|
Natural
gas
margins
|
|
|
|
|
Realized
natural gas margins (primarily wholesale)
|
|
$
|
11.1
|
|
|
|
|
|
|
Other
significant items:
|
|
|
|
|
Spot
to
forward differential
|
|
|
6.4
|
|
Unrealized
loss on Ohio mass market options
|
|
|
(1.8
|
)
|
Other
mark-to-market activity
|
|
|
3.2
|
|
Net
increase
in natural gas margins
|
|
$
|
18.9
|
|
|
|
|
|
|
Total
increase
in ESI's margin
|
|
$
|
60.9
|
|
ESI's
electric and
other margins increased $42.0 million (97.9%) for the six months ended
June 30, 2006, compared to the six months ended in 2005. The following
items were the most significant contributors to the net change in ESI's electric
and other margins:
·
|
Realized
and unrealized gains on structured origination contracts
- ESI's
electric and other margin increased $6.7 million for the six months
ended June 30, 2006, compared to the same period in 2005, due to
realized and unrealized gains from origination contracts involving
the
sale of energy through structured transactions to wholesale customers
in
the northeastern United States. These origination contracts were
not in
place in the first half of 2005. ESI continues to expand its wholesale
origination capabilities with a focus on physical, customer-based
purchase
and sale agreements in areas where it has market
expertise.
|
·
|
Retail
electric operations
- The margin
from retail electric operations decreased $10.7 million. The margin
from retail electric operations in Michigan decreased $4.0 million,
the margin from retail electric operations in Ohio decreased
$3.6 million, and the margin from retail operations in northern Maine
decreased $1.4 million. Results from retail electric operations in
Michigan have been negatively impacted by customer attrition in
Michigan
as a result of tariff changes granted to Michigan utilities and
high
wholesale energy prices, but these items were partially offset
by the
elimination of the SECA effective March 31, 2006 (see "Other Future
Considerations" for more information on ESI's retail electric operations
in Michigan). ESI's retail electric aggregation sales in Ohio ended
on
December 31, 2005, with the expiration of ESI's contracts with Ohio
aggregation customers. ESI remains prepared to offer future retail
electric service in Ohio and increase future retail electric service
in
Michigan as the regulatory climate and market conditions allow.
The
decrease in margin from retail electric operations in northern
Maine was
driven by higher supply costs tied to rising diesel fuel prices.
A portion
of the electricity purchased by ESI to supply customers in northern
Maine
is derived from burning wood chips. The cost to transport wood
chips as
well as the operating costs of the machine utilized to make the
wood chips
are negatively impacted by rising diesel fuel prices. ESI shares
in this
diesel fuel exposure with the generation supplier.
|
·
|
Other
wholesale electric operations
- A
$26.9 million increase in margin from other wholesale electric
operations was driven by an increase in net realized and unrealized
gains
related to trading activities utilized to optimize the value of
ESI's
merchant generation fleet and customer supply portfolios. As part
of its
trading activities, ESI seeks to generate profits from the volatility
of
the price of electricity, by purchasing or selling various financial
and
physical instruments (such as forward contracts, options, financial
transmission rights, and capacity contracts) in established wholesale
markets (primarily in the northeastern portion of the United States
where
ESI has market expertise) under risk management policies set by
management
and approved by WPS Resources' Board of Directors. ESI also seeks to
maximize the value of its generation and customer supply portfolios
to
reduce market price risk and extract additional value from these
assets
through the use of various financial and physical instruments (such
as
forward contracts, options, financial transmission rights, and
capacity
contracts). Period-by-period variability in the margin contributed
by
ESI's optimization strategies and trading activities is expected
due to
constantly changing market conditions. ESI continues to produce
strong
results from its optimization and trading activities and believes
it
maintains a relatively low risk profile. A diverse mix of products
and
markets, combined with disciplined execution and exit strategies
have
allowed ESI to consistently generate economic value and earnings
while
staying within WPS Resources' Board of Directors' authorized
value-at-risk (VaR) limits. For more information on VaR, see "Item
3,
Quantitative and Qualitative Disclosures about Market
Risk."
|
·
|
Oil
option
activity, net
- An
increase in mark-to-market and realized gains on derivative instruments
utilized to protect the value of a portion of ESI's Section 29/45K
federal
tax credits in 2006 and 2007 contributed $20.8 million to the
increase in its electric and other margin. The derivative instruments
have
not been designated as hedging instruments and, as a result, changes
in
the fair value are recorded currently in earnings. The benefit
from
Section 29/45K federal tax credits during a period is primarily
based upon
estimated annual synthetic fuel production levels, annual taxable
earnings
projections, and any impact projected annual oil prices may have on
the realization of Section 29/45K federal tax credits. This results
in
mark-to-market gains or losses being recognized in different periods,
compared to any tax credit phase-outs that may be recognized. For
more information on Section 29/45K federal tax credits, see Note 11
to the Condensed Notes to Financial Statements, "Commitments and
Contingencies."
|
·
|
Unrealized
gains on non-qualifying hedges
- ESI
mitigates market price risk fluctuations associated with its merchant
generation fleet using derivative instruments; including basis
swaps,
futures, forwards, and options, in addition to other instruments.
Effective in the first quarter of 2006, derivative instruments
used to
mitigate the market price risk associated with ESI's Niagara generation
facility no longer qualified for hedge accounting under generally
accepted
accounting principles. The designation of these derivative instruments,
previously recorded as cash flow hedges, resulted in the recognition
of a
$2.0 million unrealized gain in the first quarter of
2006.
|
·
|
Increased
costs related to the liquidation of an electric supply contract
in
2005
- In the
fourth quarter of 2005, an electricity supplier exiting the wholesale
market in Maine requested that ESI liquidate a firm contract to
buy power
in 2006 and 2007. At that time, ESI recognized an $8.2 million gain
related to the liquidation of the contract and entered into a new
contract
with another supplier for firm power in 2006 and 2007 to supply
its
customers in Maine. The cost to purchase power under the new contract
is
more than the cost under the liquidated contract. As a result of
the
termination of this contract, purchased power costs to serve customers
in
Maine will be $6.4 million higher for the year ended
December 31, 2006, and slightly higher than the original contracted
amount in 2007. The liquidation of this contract had a $3.7 million
negative impact on the electric and other margin for the six months
ended
June 30, 2006, resulting from higher purchased power costs recorded
under the new contract.
|
The
natural gas
margin at ESI increased $18.9 million (56.3%) for the six months ended
June 30, 2006, compared to the same period in 2005. The following items
were the most significant contributors to the change in ESI's natural gas
margin:
·
|
Realized
natural gas margins (primarily wholesale)
-
Realized
natural gas margins increased $11.1 million for the six months ended
June 30, 2006, compared to the same period in the prior year. The
majority of this increase was due to an increase in structured
wholesale
natural gas transactions related to an increase in the volatility
of the
price of natural gas and high natural gas storage spreads during
the first
half of 2006. ESI also realized margin from the withdrawal of natural
gas
from its Kimball storage field in the second quarter of 2006. ESI
was
required to withdraw a certain amount of gas from Kimball prior
to the
sale of the facility, which was completed in the second quarter
of 2006.
The average price of natural gas stored in the Kimball facility
was less
than the hedged price at the time of withdrawal. See Note 5 to
the
Condensed Notes to Financial Statements, "Acquisitions
and Sales of Assets,"
for more
information on the Kimball sale.
|
·
|
Spot
to
forward differential -
The natural
gas storage cycle had a $6.4 million positive period over period
impact on ESI's margin. For the six months ended June 30, 2006, the
natural gas storage cycle had a $1.3 million positive impact on ESI's
natural gas margin, compared to a $5.1 million negative impact on
margin for the same period of 2005. At June 30, 2006, there was a
$4.5 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 2006/2007 natural gas storage cycle. This
$4.5 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 2006/2007 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.
|
·
|
Unrealized
loss on Ohio mass market options -
Options
utilized to manage supply costs for Ohio mass market customers,
which were
purchased in the latter half of 2005 and expire in varying months
through
September 2006, had a $1.8 million negative period over period impact
on ESI's natural gas margin. For the six months ended June 30, 2006,
these options had a $2.6 million negative impact on ESI's natural gas
margin, compared to a $0.8 million negative impact on margin for the
six months ended June 30, 2005. These contracts are utilized to
reduce the risk of price movements and changes in consumer consumption
patterns. Earnings volatility results from the application of derivative
accounting rules to the options (requiring that these derivative
instruments be marked-to-market), without a corresponding mark-to-market
offset related to the customer contracts. Full requirements natural
gas
contracts with ESI's customers are not considered derivatives and,
therefore, no gain or loss is recognized on these contracts until
settlement.
|
·
|
Other
mark-to-market activity
-
Mark-to-market
gains on derivatives not previously discussed totaling $2.8 million
were recognized for the six months ended June 30, 2006, compared to
the recognition of $0.4 million of mark-to-market losses on other
derivative instruments during the same period in 2005. A significant
portion of the difference relates to changes in the fair market
value of
basis swaps utilized to mitigate market price risk associated with
natural
gas transportation contracts and certain natural gas sales contracts.
Earnings volatility results from the application of derivative
accounting
rules to the basis swaps (requiring that these derivative instruments
be
marked-to-market), without a corresponding mark-to-market offset
related
to the physical natural gas transportation contracts or the natural
gas
sales contracts (as these contracts are not considered derivative
instruments). Therefore, no gain or loss is recognized on the
transportation contracts or customer sales contracts until
settlement.
|
Overview
of
Holding Company and Other Segment Operations
Holding
Company and
Other operations recognized earnings of $6.4 million during the six months
ended June 30, 2006, compared to earnings of $1.5 million during the
same period in 2005. The increase in earnings was driven by a $7.6 million
increase in pre-tax equity earnings from ATC and a $6.2 million pre-tax
gain recognized from the sale of the company's one-third interest in
Guardian Pipeline, LLC, partially offset by a $3.7 million
pre-tax increase in operating and maintenance expenses (primarily related
to
business expansion activities) and an increase in interest expense. Pre-tax
equity earnings from ATC were $18.7 million for the six months ended
June 30, 2006, compared to $11.1 million for the six months ended
June 30, 2005.
Operating
Expenses
|
|
Six
Months
Ended June 30,
|
|
WPS Resources'
Operating Expenses (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
251.2
|
|
$
|
261.1
|
|
|
(3.8
|
%)
|
Depreciation
and decommissioning expense
|
|
|
49.6
|
|
|
95.8
|
|
|
(48.2
|
%)
|
Taxes
other
than income
|
|
|
27.2
|
|
|
23.8
|
|
|
14.3
|
%
|
Operating
and
Maintenance Expense
Operating
and
maintenance expenses decreased $9.9 million (3.8%) for the six months ended
June 30, 2006, compared to the same period in 2005. Utility operating and
maintenance expenses decreased $12.6 million (5.9%), driven by a
$34.9 million decrease in operating and maintenance expenses at WPSC,
partially offset by $20.7 million of operating and maintenance expenses
incurred during the six months ended June 30, 2006 by MGUC (assets acquired
on April 1, 2006) and MERC (assets acquired on July 1, 2006), and also by
a
$1.6 million increase in operating and maintenance expenses at UPPCO. Of
the $20.7 million of operating and maintenance expenses incurred by MGUC
and MERC, $8.2 million related to external transition costs (discussed
above). All operating and maintenance expenses incurred by MERC during the
six
months ended June 30, 2006, related to transition costs. The increase in
UPPCO's operating and maintenance expenses was driven by higher customer
write-offs and benefit costs. The following items were the most significant
contributors to the change in operating and maintenance expenses at
WPSC:
·
|
WPSC
refunded
$30.0 million of the proceeds received from the liquidation of the
Kewaunee nonqualified decommissioning trust fund to ratepayers
during the
six months ended June 30, 2006. This reduction in revenue was offset
by a related decrease in operating expenses, due to the partial
amortization of the regulatory liability recorded for the refund
of this
fund.
|
·
|
Operating
and
maintenance expenses related to the Kewaunee nuclear plant decreased
approximately $22 million due to the sale of this facility in July
2005. The decrease in operating and maintenance expenses related
to
Kewaunee did not have a significant impact on net income as WPSC
is still
purchasing power from this facility in the same amount as its original
ownership interest. The cost of the power is included as a component
of
utility cost of fuel, natural gas, and purchased power.
|
·
|
Excluding
Kewaunee, maintenance expenses at WPSC increased $3.9 million for the
six months ended June 30, 2006, compared to the same period in 2005.
Planned maintenance was required on certain combustion turbines
in the
first half of 2006, and maintenance expenses related to electric
distribution assets also increased.
|
·
|
Customer
account expenses increased $2.5 million, driven by an increase in
consulting fees related to the implementation of a new software
system.
|
·
|
Write-offs
of
uncollectible customer accounts increased $1.9 million in the first
half of 2006, compared to the same period in 2005, due primarily
to higher
energy costs.
|
·
|
Transmission-related
expenses and amortization of other previously deferred regulatory
assets
also increased during the six months ended June 30, 2006, compared to
the same period in 2005.
|
Operating
and
maintenance expenses at ESI decreased $0.5 million, driven by a
$9.0 million pre-tax gain recognized on the sale of ESI's Kimball storage
field in the second quarter of 2006. This gain was partially offset by higher
payroll and benefit costs related to ESI's continued business
expansion.
Operating
and
maintenance expenses related to the Holding Company and Other Segment Operations
increased $3.7 million for the six months ended June 30, 2006,
compared to the same period in the prior year, primarily related to business
expansion activities.
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $46.2 million (48.2%) for the six months
ended June 30, 2006, compared to the same period in 2005, driven by
approximately $41 million of decommissioning expense that was recorded
during the six months ended June 30, 2005, compared to no decommissioning
expense recorded in 2006, and a $9.5 million decrease in depreciation
expense resulting from the sale of Kewaunee in July 2005. Subsequent to the
sale
of Kewaunee, decommissioning expense is no longer recorded. In 2005, realized
gains on decommissioning trust assets were substantially offset by
decommissioning expense pursuant to regulatory practice (see analysis of
"Other
Income
(Expense)"
below).
Depreciation expense of $1.8 million was recorded at MGUC during the second
quarter of 2006, partially offsetting the decreases discussed above. Continued
capital investment at WPSC also partially offset the overall decrease in
depreciation and decommissioning expense.
Taxes
Other
Than Income
Taxes
other than
income increased $3.4 million (14.3%), primarily due to a $1.8 million
increase in gross receipts taxes paid by WPSC due to higher revenues and
$1.0 million of other taxes recorded by MGUC, primarily related to property
taxes.
Other
Income (Expense)
|
|
Six
Months
Ended June 30,
|
|
WPS Resources'
Other Income (Expense) (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
$
|
22.9
|
|
$
|
53.2
|
|
|
(57.0
|
%)
|
Interest
expense
|
|
|
(40.5
|
)
|
|
(30.0
|
)
|
|
35.0
|
%
|
Minority
interest
|
|
|
2.4
|
|
|
2.2
|
|
|
9.1
|
%
|
Other
(expense) income
|
|
|
($15.2
|
)
|
$
|
25.4
|
|
|
-
|
|
Miscellaneous
Income
Miscellaneous
income decreased $30.3 million (57.0%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005.
The decrease in miscellaneous income was driven by approximately
$41 million of realized gains on nuclear decommissioning trust assets
recorded during the six months ended June 30, 2005. Pursuant to regulatory
practice, the increase in miscellaneous income related to the 2005 realized
gains was substantially offset by an increase in decommissioning expense
in
2005. Miscellaneous income was also negatively impacted as ESI's share of
operating losses related to its equity method investment in a synthetic fuel
facility increased by $4.0 million in the first half of 2006, compared to
the first half of 2005. In the first half of 2006, ESI elected to take more
production then it had taken in the first half of 2005. This opportunity
presented itself after ESI's partners in this facility curtailed their
production in the second quarter of 2006. See Note 11 "Commitments
and
Contingencies,"
for more
information related to ESI's investment in the synthetic fuel facility. The
decreases in decommissioning trust earnings and increase in operating losses
related to the synthetic fuel facility were partially offset by a
$6.2 million pre-tax gain recognized from the sale of the company's
one-third interest in Guardian Pipeline, LLC, and a $7.6 million increase
in pre-tax equity earnings from ATC.
Interest
Expense
Interest
expense
increased $10.5 million (35.0%) for the six months ended June 30,
2006, compared to the same period in 2005, due primarily to an increase in
the
average amount of short-term debt outstanding and higher interest rates on
short-term debt. In the first half of 2006, short-term debt was primarily
utilized to purchase the natural gas distribution operations in Michigan,
fund
the construction of Weston 4, and for working capital requirements at ESI.
Provision
for Income Taxes
The
effective tax
rate was 31.5% for the six months ended June 30, 2006, compared to 20.6%
for the six months ended June 30, 2005. The increase in the effective tax
rate was driven by an increase in income before taxes combined with a decrease
in Section 29/45K federal tax credits recognized in the first half of 2006,
compared to the same period in 2005. Our
ownership
interest in a synthetic fuel operation, along with the procurement of additional
tons of synthetic fuel from our partners in this operation in the second
quarter
of 2006, resulted in recognizing the tax benefit of Section 29/45K federal
tax credits totaling $7.6 million in the first half of 2006, compared to
$18.6 million in the same period of 2005. The decrease in Section 29/45K
federal tax credits recognized was driven by the impact high oil prices
may have on our ability to realize the benefit of Section 29/45K federal
tax credits, partially offset by the Section 29/45K federal tax credits
recognized on the additional production procured from our synfuel
partner.
At
June 30, 2006, based upon estimated annual average oil prices, we
anticipate that approximately 76% of the 2006 tax credits that otherwise
would
be available from the production and sale of synthetic fuel would be phased-out.
WPS Resources estimates that, at June 30, 2006, an additional
$17 million of tax credits would have been recognized related to its
ownership interest in the synthetic fuel operation (including the additional
tons procured) in the first half of 2006 absent the projected tax credit
phase-out. See Note 11 "Commitments
and
Contingencies,"
for more
information related to Section 29/45K federal tax credits.
Discontinued
Operations
The
loss from
discontinued operations (Sunbury) increased $3.9 million, from
$0.5 million for the six months ended June 30, 2005, to
$4.4 million for the same period in 2006. The increased loss was driven by
an $8.9 million ($5.3 million after-tax) decrease in gross margin, a
$7.5 million ($4.6 million after-tax) increase in operating and
maintenance expenses, partially offset by a $10.6 million
($6.4 million after-tax) decrease in interest expense. While production
increased for the six months ended June 30, 2006, compared to the same
period in 2005, gross margin decreased as a result of the higher cost of
fuel
and emission allowances. Since the sale of its allocated emission allowances
in
the second quarter of 2005,
Sunbury
must
purchase emission allowances required for operation at market prices. In
the
second quarter of 2005, Sunbury recognized a pre-tax gain of $85.9 million
from the sale of its allocated emission allowances, which was substantially
offset by an impairment loss of $80.6 million related to the Sunbury plant.
The net $5.3 million pre-tax gain resulting from these items in the second
quarter of 2005 in addition to increased maintenance expense at Sunbury in
the
first half of 2006, drove the period-over-period increase in operating and
maintenance expenses. The decrease in interest expense was driven by
$9.1 million of interest expense recognized in the second quarter of 2005
related to the termination of an interest rate swap pertaining to Sunbury's
non-recourse debt obligation in addition to the recognition of interest expense
on the non-recourse debt prior to the restructuring of this debt in the second
quarter of 2005. The restructuring of the Sunbury debt to a WPS Resources
obligation in June 2005 triggered the recognition of interest expense
equivalent to the mark-to-market value of the swap at the date of
restructuring.
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-term 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 "Financing
Cash
Flows - Credit Ratings,"
below).
Operating
Cash Flows
During
the six
months ended June 30, 2006, net cash used for operating activities was
$25.6 million, compared with $197.7 million provided by operating
activities for the same period in 2005. The $223.3 million decrease in net
cash provided by operating activities was driven by a $239.1 million
increase in cash required to fund working capital requirements, primarily
at
ESI, which resulted from an increase in natural gas inventories from
December 31, 2005, to June 30, 2006, compared to a decrease in natural
gas inventories from December 31, 2004, to June 30, 2005. The increase
in natural gas inventories is related to an increase in structured wholesale
natural gas transactions in 2006 due to an increase in the volatility of
the
price of natural gas and wide natural gas storage spreads.
Investing
Cash Flows
Net
cash used for
investing activities was $785.8 million during the six months ended
June 30, 2006, compared to $216.5 million during the same period in
2005. The change is primarily due to $333.3 million of cash that was placed
in escrow to finance the July 1, 2006 acquisition of the Minnesota natural
gas
distribution operations from Aquila, $317.9 million of cash paid for the
acquisition of the Michigan natural gas distribution operations from Aquila,
and
an increase in contributions to ATC and other investments. A decrease in
capital
expenditures at WPSC (discussed below), proceeds of $38.5 million received
from the sale of the company’s one-third interest in Guardian Pipeline, LLC, and
proceeds of $19.9 million received from the sale of WPS ESI Gas
Storage (which owns a natural gas storage field located in the Kimball Township,
St. Clair County, Michigan) partially offset the increase in cash used for
investing activities.
During
the first
six months of 2006, WPS Resources invested $22.4 million in ATC
(related to its requirement to fund a portion of the Wausau, Wisconsin, to
Duluth, Minnesota, transmission line), compared to $21.5 million in the
first six months of 2005. This increased WPS Resources' consolidated
ownership interest in ATC to approximately 33%.
Capital
Expenditures
Capital
expenditures by business segment for the six months ended June 30 were as
follows:
(Millions)
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
Electric
utility
|
|
$
|
134.4
|
|
$
|
171.1
|
|
Gas
utility
|
|
|
17.0
|
|
|
14.2
|
|
ESI
|
|
|
3.3
|
|
|
2.6
|
|
Other
|
|
|
(0.5
|
)
|
|
0.5
|
|
WPS Resources
consolidated
|
|
$
|
154.2
|
|
$
|
188.4
|
|
The
decrease in
capital expenditures at the electric utility for the six months ended
June 30, 2006, as compared to the same period in 2005, is mainly due to
lower capital expenditures associated with the construction of Weston 4, as
a result of the sale of a 30% interest in the project to DPC in the fourth
quarter of 2005. Commercial operation for Weston 4 is still expected to occur
in
June 2008.
Financing Cash
Flows
Net
cash provided
by financing activities was $797.4 million during the six months ended
June 30, 2006, compared to net cash used for financing of
$68.5 million during the same period in 2005. The change is primarily
attributed to $738.0 million of cash received from commercial paper
borrowings during the first six months of 2006. Cash receipts of
$139.6 million for the settlement of the forward equity sale agreement also
contributed to the change. These funds were used primarily for the acquisitions
of the natural gas distribution operations in Michigan and Minnesota,
construction expenditures related to Weston 4,
working capital requirements at ESI, and for other general corporate purposes.
WPS Resources was able to pay down $29.9 million of commercial paper
borrowings in 2005 from cash received from operating activities.
Significant
Financing Activities
WPS Resources
had outstanding commercial paper borrowings of $834.2 million and
$249.9 million at June 30, 2006, and 2005, respectively.
WPS Resources
had other outstanding short-term debt of $168.6 million and
$10.0 million as of June 30, 2006, and 2005, respectively. Of the
$168.6 million, $158.6 million relates to ESI and $10.0 million
relates to WPSC. In April 2006, ESI entered into a $150 million 364-day
credit agreement to finance its margin requirements related to natural gas
and
electric contracts traded on the NYMEX and the ICE, as well as the cost of
natural gas in storage and for general corporate purposes. Borrowings under
this
agreement are guaranteed by WPS Resources. As of June 30, 2006, the
entire $150 million available under the credit agreement was utilized by
ESI.
In
the second quarter of 2006 and 2005, 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
$12.3 million and $19.2 million for the six months ended June 30,
2006, and 2005, respectively. Equity also increased $139.6 million in 2006
due to the physical settlement of the equity forward agreement in May 2006
(see
below). WPS Resources did not repurchase any existing common stock during
the six months ended June 30, 2006, or 2005.
In
November 2005, WPS Resources entered into a forward equity sale agreement
with an affiliate of J.P. Morgan Securities, Inc., as forward purchaser,
relating to 2.7 million shares of WPS Resources' common stock. On May
10, 2006, WPS Resources physically settled the forward equity agreement
(and, thereby, issued 2.7 million shares of common stock) and received
proceeds of $139.6 million. The
proceeds
were used
to pay down commercial paper borrowings originally utilized to finance the
acquisition of the natural gas distribution operations in Michigan and for
general corporate purposes.
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, UPPCO, MGUC, and MERC.
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
|
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.
In
July 2006, 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 signed a definitive merger agreement
with Peoples Energy. Standard & Poor's stated that the CreditWatch listing
on WPS Resources reflects concerns that the company's credit profile will
be pressured by several post-merger factors, including a challenging Illinois
regulatory environment, heightened exposure to energy marketing activities,
exposure to the volatile oil and gas exploration and production sector, higher
leverage at Peoples Energy, and a commitment to increase the dividend paid
to
current WPS shareholders.
In
July 2006, Moody's placed the ratings of WPS Resources' A1 senior unsecured
debt and P-1 commercial paper and WPSC's Aa2 senior secured debt and Aa3
credit
facility under review for possible downgrade following the announcement that
WPS Resources signed a definitive merger agreement with Peoples Energy.
WPSC's P-1 rating for commercial paper was affirmed. The review for downgrade
reflects expectations that the proposed merger with lower rated Peoples Energy
would increase the proportion of higher risk non-regulated businesses under
WPS Resources following the merger.
Rating
agencies use
a number of both quantitative and qualitative measures in determining a
company's credit rating. These measures include 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 both WPS Resources and WPSC. 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
the availability of funds to the companies 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 trading
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 would be able to conduct.
ESI
uses the NYMEX,
the ICE, and over-the-counter financial markets to mitigate its exposure
to
physical customer obligations. These contracts are closely correlated to
the
customer contracts, but price movements on the contracts may require
financial backing. Certain movements in price for contracts through the NYMEX
and the ICE 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 only result in a temporary
liquidity need that will unwind as the sales contracts are fulfilled.
Discontinued
Operations
Net
cash provided
by discontinued operations was $3.8 million during the six months ended
June 30, 2006, compared to $70.5 million during the same period
in 2005. The decrease in cash provided by discontinued operations was driven
by
$110.9 million of proceeds received from the sale of Sunbury's allocated
emission allowances during the six months ended June 30, 2005.
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
June 30, 2006
(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
|
|
$
|
1,221.1
|
|
$
|
28.3
|
|
$
|
111.7
|
|
$
|
312.4
|
|
$
|
768.7
|
|
Operating
lease obligations
|
|
|
20.9
|
|
|
2.4
|
|
|
7.4
|
|
|
5.0
|
|
|
6.1
|
|
Commodity
purchase obligations
|
|
|
7,638.3
|
|
|
2,215.7
|
|
|
3,617.6
|
|
|
932.7
|
|
|
872.3
|
|
Purchase
orders
|
|
|
478.1
|
|
|
355.2
|
|
|
122.8
|
|
|
0.1
|
|
|
-
|
|
Capital
contributions to equity method investment
|
|
|
57.0
|
|
|
17.9
|
|
|
39.1
|
|
|
-
|
|
|
-
|
|
Other
|
|
|
368.4
|
|
|
40.6
|
|
|
61.3
|
|
|
38.9
|
|
|
227.6
|
|
Total
contractual cash obligations
|
|
$
|
9,783.8
|
|
$
|
2,660.1
|
|
$
|
3,959.9
|
|
$
|
1,289.1
|
|
$
|
1,874.7
|
|
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, UPPCO and MGUC 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. The sale of a 30% interest in Weston 4 to DPC
was completed in November 2005, but WPSC retains the legal obligation to
initially remit payment to third parties for 100% of all construction costs
incurred, 30% of which will subsequently be billed to DPC. Capital contributions
to equity method investment consist of our commitment to fund a portion of
ATC's
Wausau, Wisconsin, to Duluth, Minnesota, transmission line together with
ATC.
Other mainly represents expected pension and postretirement funding obligations.
The table above does not reflect obligations under the definitive agreement
with
Aquila to acquire its natural gas distribution operations in Minnesota, which
is
discussed in Note 5, "Acquisitions
and Sales of Assets,"
in the Condensed
Notes to Financial Statements.
Capital
Requirements
WPSC
makes large
investments in capital assets. Net construction expenditures are expected
to be
$898.7 million in the aggregate for the 2006 through 2008 period. The
largest of these expenditures is for the construction of Weston 4. WPSC is
expected to incur costs of approximately $280 million from 2006 through
2008 related to its 70% ownership interest in this facility.
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 is responsible for slightly more than 70% (approximately
$549 million) of the costs. In November 2005, DPC purchased a 30% ownership
interest in Weston 4, remitting proceeds of $95.1 million for its
share of the construction costs (including carrying charges) as of the closing
date of the sale. WPSC is responsible for slightly more than 70% of the costs
because of certain common facilities that will be installed as part of the
project. WPSC will have a larger than 70% interest in these common facilities.
DPC will be billed by WPSC for 30% of all remaining costs to complete the
construction of the plant. As of June 30, 2006, WPSC has incurred a total
cost of $363.9 million related to its ownership interest in the project. In
addition to the costs discussed above, WPSC expects to incur additional
construction costs through the date the plant goes into service of approximately
$82 million to fund construction of the transmission facilities required to
support Weston 4. ATC will reimburse WPSC for the construction costs of
these transmission facilities and related carrying costs when Weston 4
becomes commercially operational, which is expected to occur in
June 2008.
Other
significant
anticipated construction expenditures for WPSC during the three-year period
2006
through 2008 include approximately $357.3 million of distribution projects
(including replacement of utility poles, transformers, meters, etc.),
environmental projects of approximately $169 million, other expenditures at
WPSC generation plants to ensure continued reliability of these facilities
of
approximately $52 million, and corporate services infrastructure projects
of approximately $32 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 ATC.
WPS Resources committed to fund 50% of total project costs incurred up to
$198 million. WPS Resources will receive additional equity in ATC in
exchange for the project funding. WPS Resources may terminate funding
if the project extends beyond January 1, 2010. The total cost of the project
is
estimated at $420.3 million and it is expected that the line will be
completed and 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. However, WPS Resources' future
funding of the line will be reduced by the amount funded by Allete, Inc.
Allete
has exercised its option to fund a portion of the Wausau to Duluth transmission
line. WPSC and Allete agreed that Allete will fund up to $60 million of
future capital calls for the line. Considering this, for the period
January
2006
through the completion of the line in 2008, WPS Resources expects to fund
up to approximately $61 million for its portion of the Wausau to Duluth
transmission line.
WPS Resources
expects to provide additional capital contributions to ATC of approximately
$78 million for the period 2006 through 2008 for other projects.
UPPCO
is expected
to incur construction expenditures of about $48 million in the aggregate
for the period 2006 through 2008, primarily for electric distribution
improvements and repairs and safety measures at hydroelectric
facilities.
MGUC
is expected to
incur construction expenditures of approximately $24 million in the
aggregate for the period 2006 through 2008, primarily for natural gas mains,
maintenance, and miscellaneous expenses.
Capital
expenditures identified at ESI for 2006 through 2008 are expected to be
approximately $9 million largely due to scheduled major maintenance
projects at ESI's generation facilities and 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 2006
through 2008 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 June 30, 2006, 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 2006
through 2008, 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.
In
June 2006, WPS Resources entered into an unsecured $500 million
5-year credit agreement. This revolving credit facility replaced the
$300 million bridge credit facility discussed below and is in addition to
the previously existing credit facility which also has a borrowing capacity
of
$500 million, bringing WPS Resources' total borrowing capacity under
its general credit agreements to $1 billion. Both credit facilities back
WPS Resources' commercial paper borrowing programs and letters of credit.
The first credit line was entered into in June 2005, and is an unsecured
$500 million 5-year credit agreement. In June 2005, WPSC also entered into
a 5-year credit facility for $115 million to replace its former 364-day
credit facility for the same amount. This credit line is used to back 100%
of
WPSC's commercial paper borrowing programs and letters of credit for WPSC.
As of
June 30, 2006, there was a total of $592.9 million and
$26.2 million available under WPS Resources' and WPSC's credit lines,
respectively.
In
April 2006, WPS Resources filed a shelf registration under the new SEC
securities offering reform rules for the ability to issue debt, equity, and
certain types of hybrid securities. This shelf registration statement includes
the unused capacity remaining under WPS Resources' prior registration
statement. Specific terms and conditions of securities issued will be determined
prior to the actual issuance of any specific security. Under the new SEC
securities offering reform rules, WPS Resources will be able to issue
securities under this registration statement for three years.
WPS Resources' Board of Directors has authorized the issuance of up to
$700 million of equity, debt, or other securities under this shelf
registration statement.
In
April 2006, ESI entered into a $150 million 364-day credit agreement to
finance its margin requirements related to natural gas and electric contracts
traded on the NYMEX and the ICE, as well as the cost of natural gas in storage
and for general corporate purposes. Borrowings under this agreement are
guaranteed by WPS Resources. As of June 30, 2006, the entire
$150 million available under the credit agreement was utilized by
ESI.
In
November 2005, WPS Resources entered into two unsecured revolving
credit agreements of $557.5 million and $300 million with J.P. Morgan
Chase Bank and Bank of America Securities LLC. As discussed above, the
$500 million 5-year credit agreement entered into in June 2006
replaced the $300 million bridge credit facility. The $557.5 million
credit facility is a bridge facility intended to backup commercial paper
borrowings related to the purchase of the natural gas distribution operations
in
Michigan and Minnesota. The capacity under the $557.5 million bridge facility
is
reduced by the amount of proceeds from any long-term financing we complete,
with
the exception of proceeds received from the November 2005
equity offering. On May 10, 2006, as a result of WPS Resources physical
settlement of its forward equity agreement (and issuing 2.7 million shares
of common stock upon settlement), the $557.5 million facility was reduced
to $417.9 million. This credit agreement will be further reduced as
permanent or replacement financing is secured. The $417.9 million credit
agreement matures on September 5, 2007, and has representations and
covenants that are similar to those in our general credit facilities. On
March 31, 2006, in order to meet short-term financing requirements related
to the acquisition of the natural gas distribution operations in Michigan,
WPS Resources issued $269.5 million of commercial paper supported by
the $417.9 million bridge credit facility. On June 30, 2006, in order
to meet short-term financing requirements related to the acquisition of the
natural gas distribution operations in Minnesota, WPS Resources issued
commercial paper in the amount of $333.3 million, partially supported by
the $417.9 million bridge facility, with the remaining commercial paper
supported by the general credit facilities discussed above. See Note 5,
"Acquisitions
and Sales of Assets,"
for more
information related to the acquisitions of the natural gas distribution
operations in Michigan and Minnesota.
Other
Future Considerations
Proposed
Merger
with Peoples Energy Corporation
For
an update on
the proposed merger with Peoples Energy, see Note 5, "Acquisition
and
Sales of Assets."
Agreement
to
Purchase Aquila's Michigan and Minnesota Natural Gas Distribution
Operations
For
an update on
the acquisition of Aquila's natural gas distribution operations in Michigan
and
Minnesota, see Note 5, "Acquisition
and
Sales of Assets."
Beaver
Falls
For
a discussion of
the Beaver Falls outage, see Note 11, "Commitments
and
Contingencies."
Asset
Management Strategy
WPS Resources
continues to evaluate alternatives for the sale of the balance of its identified
real estate holdings no longer needed for operation.
Regulatory
Matters and Rate Trends
On
August 2, 2006, WPS Resources and Peoples Energy (the "Applicants") filed a
joint application with the ICC to approve the merger between the Applicants.
The
Applicants requested an expedited proceeding as we believe the ICC to be
the
critical path to the closing of the merger. Key components of the application
include an expected rate filing for Peoples Gas Light and Coke (PGL) and
North
Shore
Gas
(NS) in early
2007, based on a 2006 historical test year. The Applicants requested that
this
filing not include either the costs to achieve or the synergies, but represent
a
"pre-close" cost of service. Also, PGL and NS would not file another rate
case
before February 1, 2009.
Under
the
prevailing Wisconsin fuel rules, WPSC's 2006 electric rates are subject to
adjustment when electric generation fuel and purchased power costs fall outside
of a pre-determined band. This band was set at +2.0% and -0.5%, for 2006
by the
PSCW. On March 8, 2006, the PSCW filed a notice of proceeding to review fuel
rates as WPSC fuel costs were below the 0.5% limit. On April 25, 2006, WPSC
filed with the PSCW a stipulation and agreement with various interveners
to
refund a portion of the difference between fuel costs that were projected
in the
2006 Wisconsin retail rate case and actual Wisconsin retail fuel costs incurred
from January through March 2006 as well as the projected savings in
April through June 2006. This refund will be a credit to customers'
bills over the months of May 2006 to August 2006. A current liability of
$3.1 million has been recorded at June 30, 2006, for a portion of the
savings realized through June 30, as well as actual refunds to customers of
$4.6 million through June 30. Rates
remain
subject to refund under the agreement through the end of the year. Fuel and
purchased power costs are expected to be greater than what will be recovered
in
rates in the second half of the year, which should negatively impact margins
during that period.
Because
a
significant portion of WPSC's electric load is served by natural gas-fired
generation, the volatile nature of natural gas prices, and the relatively
narrow
tolerance band in Wisconsin, the likelihood for future rate adjustment under
the
fuel rules in 2006 is strong. To mitigate the risk of the potential for
unrecoverable fuel costs in 2006 due to market price volatility, WPSC is
employing risk management techniques pursuant to its PSCW approved Risk Plan
and
Policy, including the use of derivative instruments such as futures and
options.
The
price of
natural gas is currently high compared to historical levels. While the WPSC
natural gas utility is authorized to obtain one-for-one recovery of prudently
incurred natural gas costs in both the Wisconsin and Michigan jurisdictions,
the
currently high natural gas rates could impact the ability of retail customers
to
pay for natural gas service and, therefore, increase WPSC's exposure to
write-offs during 2006.
In
WPSC's 2006 retail electric rate proceeding, the PSCW applied a "financial
harm"
test when considering the rate recovery of certain deferred costs previously
authorized for accounting purposes. While the application of a financial
harm
test is authorized, the PSCW has not applied it in the past when considering
the
rate recovery of costs that were previously authorized for deferral. In WPSC's
2006 rate proceeding, after applying the financial harm test, the PSCW
disallowed rate recovery of the 2004 extended outage at Kewaunee. The PSCW
also
disallowed recovery of 50% of the pre-tax loss realized on the sale of Kewaunee.
None of these disallowed costs were found to be imprudent by the PSCW.
Notwithstanding the PSCW's decision on these Kewaunee related deferred costs,
WPSC still believes it is probable that all regulatory assets recorded at
June 30, 2006, will be able to be collected from ratepayers.
For
a discussion of
regulatory filings and decisions, see Note 17, "Regulatory
Environment,"
in the Condensed
Notes to Financial Statements.
In
both 2005 and 2006, forecasting and monitoring of fuel costs have become
extremely difficult for both the PSCW and WPSC. These challenges can be
attributed to the implementation of the MISO Day 2 market and the recent
volatility in natural gas prices. The PSCW has received several applications
from various Wisconsin electric utilities under the PSC
Chapter
116
fuel rules for large rate increases due to increased gas prices, and, on
February 7, 2006, the PSCW opened a docket to review the fuel rules. WPSC
submitted comments in hopes that revisions will be made to the current fuel
rules. WPSC believes that the PSCW's role should be one of approving a utility's
overall fuel cost management plan and determining prudence after the
fact.
Energy
Efficiency and Renewables Act
In
March 2006, Wisconsin Governor Doyle signed 2005 Wisconsin Act 141 (2005
Senate
Bill 459), the Energy Efficiency and Renewables Act, which requires Wisconsin
electric providers to increase the
amount
of renewable
electricity they sell by 2% above their current level before 2010 and 6%
above
their current level by 2015. The goal is to have 10% of the state's electricity
generated from renewable sources by 2015, which is intended to increase the
use
of renewable energy in Wisconsin, promote the development of renewable energy
technologies, and strengthen the state's energy efficiency programs.
Administrative rules are currently being drafted, and the Act is expected
to
take effect on July 1, 2007. As of June 30, 2006, approximately 4% of
WPS Resources' generation is from renewable sources. WPS Resources
continuously evaluates alternatives for cost effective renewable energy sources
and will secure reliable and efficient renewable energy sources to meet both
requirements by their respective dates.
Industry
Restructuring - Michigan
Under
the current
Electric Choice program in Michigan, ESI established itself as a significant
supplier to the industrial and commercial markets. However, prolonged high
wholesale energy prices coupled with recently
approved
tariff changes for the regulated utilities have almost eliminated 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
utilities. The high wholesale energy prices and tariff changes have caused
a
reduction in new business and renewals for ESI. ESI's Michigan retail electric
business for the second quarter of 2006 declined to less than one-third the
peak
megawatts it was in 2005, and earnings contributed by Michigan retail electric
operations in 2006 have been minimal. However, both Detroit Edison and Consumers
Energy have initiated proceedings before the MPSC for rate increases relating
to
the recovery of substantial power supply costs incurred but not included
in
rates in 2005. In addition, Electric Choice advocates continue their efforts
at
both the MPSC and the legislature. These efforts focus on the removal and
reversal of stranded cost charges and securing a corresponding energy benefit
for Electric Choice customers who must pay securitization and nuclear
decommissioning charges.
The
status of
Michigan's electric markets and more specifically the MPSC's Capacity Needs
Report of January 3, 2006, have been the subject of hearings in both the
Senate
and House Energy Committees. In addition, on April 6, 2006, Governor Granholm
issued an Executive Directive instructing MPSC Chair Peter Lark to complete
a
state energy plan no later than December 31, 2006. If legislation rolling
back the Electric Choice market is enacted, it could diminish the benefits
of
competitive supply for Michigan business customers. The impact on ESI of
all the
above coupled with the volatile wholesale power market could range from
significantly increasing Michigan business to a possible decision by ESI
to exit
Michigan's retail electric market and redirect resources to more vibrant
markets. However, it is unlikely that the most significant stakeholder, the
customer, will stand for any set of outcomes that eradicates Electric Choice.
ESI is actively participating in the legislative and regulatory process in
order
to protect its interests in Michigan.
Expansion
of
Operations into Texas
In
the fourth quarter of 2005, ESI began developing a product offering in the
Texas
retail electric market. ESI previously had a market presence in Houston with
natural gas producer services originators. Texas has a thriving market structure
(unencumbered by a regulated offering that is not market based) which has
one of
the most successful consumer choice programs in the country. In the first
half
of 2006, ESI focused on developing systems, processes, services, products,
and
controls and signed its initial Texas retail electric customers. ESI continues
to sign up new enrollments and has started to deliver power to customers
in the
Texas market in July 2006. Historically, ESI concentrated its retail activities
to the northeastern quadrant of the United States and the adjacent portion
of
Canada. Expansion into the Texas market offers an opportunity to leverage
the
infrastructure and capability ESI developed to provide products and services
that it believes customers will value.
Seams
Elimination Charge Adjustment
For
a discussion of
SECA, see the Note 17, "Regulatory
Environment,"
in the Condensed
Notes to Financial Statements.
Income
Taxes
-Section 29/45K
Federal Tax Credits-
For
a discussion of
Section 29/45K federal tax credits, see the Note 11, "Commitments
and
Contingencies,"
in the Condensed
Notes to Financial Statements.
-Peshtigo
River
Land Donation-
In
2004, WPS Resources submitted a request to have the Internal Revenue
Service (IRS) conduct a pre-filing review of a tax position related to its
2004
tax return. The tax position is related to the value of the Peshtigo River
land
donated to the WDNR in 2004, for which WPS Resources recorded a
$4.1 million income tax benefit. In May 2006, the IRS and
WPS Resources entered into a limited issue focused examination of the 2004
WPS Resources consolidated tax return, which will cover several issues,
including the Peshtigo River Land donation. We believe our position is
appropriate and will pursue this matter if challenged by the IRS upon
examination of the tax return.
Environmental
See
Note 11,
"Commitments
and
Contingencies,"
in the Condensed
Notes to Financial Statements for a detailed discussion of environmental
considerations.
Midwest
Independent Transmission System Operator
WPSC,
UPPCO, and
ESI are members of the MISO, which provides electric transmission service
and
operates a market in the Midwest, including Wisconsin and the Upper Peninsula
of
Michigan, and is based on a locational marginal pricing system. The pricing
mechanism expanded the market from a physical market to also include financial
instruments and is intended to send price signals to stakeholders where
generation or transmission system expansion is needed.
MISO
participants
offer their generation and bid their customer load into the market on an
hourly
basis. This results in net receipts from, or net obligations to, MISO for
each
hour of each day. MISO aggregates these hourly transactions and currently
provides updated settlement statements which may reflect billing
adjustments and result in an increase or decrease to the net receipt from
or net
obligation to MISO. The billing adjustments may or may not be
recovered through the rate recovery process. Market participants may dispute
the
updated settlement statements and related charges. At the end of each month,
the
amount due from or payable to MISO is estimated for those operating days
where a
7-day settlement statement is not yet available, thus significant changes
in the
estimates and new information provided by MISO in subsequent settlement
statements or through tariff interpretation changes could have a material
impact
on our results of operations.
On
April 25, 2006, the FERC issued an order regarding MISO's "Revenue Sufficiency
Guarantee" charges (RSG charges). MISO's business practice manuals and other
instructions to market participants have stated, since the implementation
of
market operations on April 1, 2005, that RSG charges will not be imposed
on
offers to supply power not supported by actual generation (also known as
virtual
supply offers). However, some market participants raised questions about
the
language of MISO's tariff concerning that issue and in October 2005, MISO
submitted to the FERC proposed tariff revisions clarifying its tariff to
reflect
its business practices with respect to RSG charges, and filed corrected tariff
sheets exempting virtual supply from RSG charges. In its April 2006 decision,
the FERC interpreted MISO's tariff to require that virtual supply offers
must be
included in the calculation of the RSG charges and that to the extent that
MISO
did not charge virtual supply offers for RSG charges, it violated the terms
of
its tariff. The FERC order then proceeded to require MISO to recalculate
the RSG
charges back to April 1, 2005, and to make refunds to customers, with
interest, reflecting the recalculated charges. In order to make such refunds,
it
is likely that MISO will attempt to impose retroactively RSG charges on those
who submitted virtual supply offers during the recalculation period. ESI
and our
electric utility segment made virtual supply offers in MISO during this period
on which no RSG charges were imposed, and thus may be subject to a claim
for
refunds from MISO (which claim will be contested). The electric utility segment
will be eligible for the refund discussed above, which is expected to more
than
offset any charges that will be imposed on the electric utility segment.
ESI,
however, is not eligible for any offsetting refunds. The FERC's April 2006
order
has been challenged by MISO and other parties, including WPS Resources, and
the eventual outcome of these proceedings is unclear. As of the date of this
report, we do not believe this issue will have a material impact on WPS
Resources’ Consolidated 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, along with oil options used to mitigate
the
risk of an increase in oil prices that could reduce the amount of Section
29/45K
federal tax credits that could be recognized. 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, ICE, and over-the-counter contracts, 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 included in assets or liabilities from risk management activities
on WPS Resources' 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 and
oil
pricing is the settled forward price curve of the NYMEX and the ICE. 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 six months ended June 30, 2006.
ESI
Mark-to-Market Roll Forward
(Millions)
|
|
Oil
Options
|
|
Natural
Gas
|
|
Electric
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of
contracts at December 31, 2005
|
|
$
|
23.6
|
|
$
|
8.2
|
|
$
|
29.8
|
|
$
|
61.6
|
|
Less:
Contracts realized or settled during period
|
|
|
5.2
|
|
|
7.2
|
|
|
18.5
|
|
|
30.9
|
|
Plus:
Changes
in fair value of contracts in existence
at June 30, 2006
|
|
|
23.1
|
|
|
69.0
|
|
|
34.4
|
|
|
126.5
|
|
Fair
value of
contracts at June 30, 2006
|
|
$
|
41.5
|
|
$
|
70.0
|
|
$
|
45.7
|
|
$
|
157.2
|
|
The
fair value of
contracts at December 31, 2005, and June 30, 2006, 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, 2005, that were no longer included in the net mark-to-market
assets as of June 30, 2006, 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, 2005, and contracts that were
entered into subsequent to December 31, 2005, which are included in ESI's
portfolio at June 30, 2006. In the above table, "changes in fair value of
contracts in existence at June 30" also includes gains and losses at the
inception of contracts when a liquid market exists. 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 (generally for contracts
with a duration of less than five years). 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
June 30, 2006
|
|
|
|
|
|
|
|
|
|
Source
of
Fair Value (Millions)
|
|
Maturity
Less
Than
1
Year
|
|
Maturity
1 to
3
Years
|
|
Maturity
4 to 5
Years
|
|
Total
Fair
Value
|
|
Prices
actively quoted
|
|
$
|
56.5
|
|
$
|
5.8
|
|
$
|
-
|
|
$
|
62.3
|
|
Prices
provided by external sources
|
|
|
53.9
|
|
|
29.322.1
|
|
|
11.7
|
|
|
94.9
|
|
Prices
based
on models and other valuation methods
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
fair
value
|
|
$
|
110.4
|
|
$
|
35.1
|
|
$
|
11.7
|
|
$
|
157.2
|
|
We
derive the pricing for most contracts in the above table from active quotes
or
external sources. "Prices actively quoted" includes exchange-traded contracts
such as NYMEX and ICE contracts and basis swaps. "Prices provided by external
sources" includes electric and natural gas contract positions for which pricing
information, used by ESI to calculate fair value, is obtained primarily through
broker quotes and other publicly available sources. "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,
as well
as oil options utilized to protect the value of a portion of ESI's Section
29/45K federal tax credits. 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 positions 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. See "Results
of
Operations -
WPS Resources" for
information
regarding earnings volatility caused by 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, 2005, are still current and that
there have been no significant changes.
WPSC
is a regulated
electric and natural gas utility as well as a holding company. Electric
operations accounted for approximately 64% of revenues for the six months
ended
June 30, 2006, while natural gas operations accounted for 36% of revenues
for the six months ended June 30, 2006.
Second
Quarter 2006 Compared with Second Quarter 2005
WPSC
Overview
WPSC's
earnings on
common stock for the quarters ended June 30 are shown in the following
table:
WPSC's
Results (Millions)
|
2006
|
2005
|
Change
|
|
|
|
|
Earnings
on
common stock
|
$25.1
|
$21.3
|
17.8.%
|
WPSC's
earnings on
common stock were $25.1 million for the quarter ended June 30, 2006,
compared to $21.3 million for the quarter ended June 30, 2005. As
discussed in more detail below, the following factors impacted earnings
for the
quarter ended June 30, 2006, compared to the same period in
2005.
·
|
Electric
utility earnings increased $3.1 million, from $20.6 million for
the quarter ended June 30, 2005 to $23.7 million for the
quarter ended June 30, 2006. The increase in electric utility
earnings was driven by fuel and purchased power costs that were
less than
were recovered in rates in the second quarter of 2006, compared
to no
significant over or under collections in the second quarter of
2005. Fuel
and purchased power costs are expected to be greater than what
will be
recovered in rates in the second half of the year, which should
negatively
impact margins during that period. A retail electric rate increase
at WPSC
also contributed to higher earnings, but the rate increase was
largely
offset by an increase in various operating and maintenance expenses.
|
·
|
The
net loss
from natural gas operations increased $0.3 million, from
$1.9 million for the quarter ended June 30, 2005, to
$2.2 million for the quarter ended June 30, 2006. Including the
natural gas rate increase that became effective on January 1,
2006, WPSC's
natural gas margin was flat compared to the prior year as unfavorable
weather conditions negatively impacted sales volumes to WPSC's
higher
margin residential, and commercial and industrial customers.
The lower
than anticipated margin was not sufficient to cover increases
in
depreciation expense and taxes other than
income.
|
Electric
Utility Operations
|
|
Three
Months
Ended June 30,
|
|
Electric
Utility Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
238.9
|
|
$
|
219.3
|
|
|
8.9
|
%
|
Fuel
and
purchased power
|
|
|
107.6
|
|
|
69.9
|
|
|
53.9
|
%
|
Margin
|
|
$
|
131.3
|
|
$
|
149.4
|
|
|
(12.1
|
%)
|
Sales
in
kilowatt-hours
|
|
|
3,481.2
|
|
|
3,517.5
|
|
|
(1.0
|
%)
|
Electric
utility
revenue increased $19.6 million (8.9%) for the quarter ended June 30,
2006, compared to the same quarter in 2005, largely due to an approved
annual
electric rate increase for WPSC's Wisconsin retail customers. In
December 2005, the PSCW approved a retail electric rate increase of
$79.9 million (10.1%), effective January 1, 2006. The retail electric rate
increase was required primarily because of higher fuel and purchased power
costs
(including costs associated with the Fox Energy Center power purchase
agreement), costs related to the construction of Weston 4, higher
transmission expenses, and recovery of a portion of the costs related to
the
2005 Kewaunee outage. Partially offsetting the items discussed above, rates
were
lowered to reflect a refund to customers in 2006 of a portion of the
proceeds
received
from the
liquidation of the nonqualified decommissioning trust fund as a result
of the
July 2005 sale of Kewaunee. The increase in electric utility revenue related
to
the rate increase was also partially offset by a 1.0% decrease in overall
electric utility sales volumes. Electric utility sales volumes to residential
customers decreased, primarily due to summer weather conditions during
the
second quarter of 2006 that were 41% cooler during the cooling season,
compared
to the same quarter in 2005. The decrease in electric sales volumes to
residential customers, however, was substantially offset by a 5.2% increase
in
sales volumes to wholesale customers, driven by higher demand.
The
electric
utility margin decreased $18.1 million (12.1%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005, primarily related to
the sale of Kewaunee, and the related power purchase agreement. Prior to
the
sale of Kewaunee, only nuclear fuel expense was reported as a component
of fuel,
natural gas, and purchased power. Subsequent to the sale, all payments
(both
variable payments for energy delivered and fixed payments) to Dominion
Energy
Kewaunee, LLC for power purchased from Kewaunee are reported as a component
of
utility cost of fuel, natural gas, and purchased power. As a result of
the sale,
WPSC no longer incurs operating and maintenance expenses, depreciation
and
decommissioning expense, or interest expense related to Kewaunee.
Excluding
the
$24.3 million of fixed payments made to Dominion Energy Kewaunee in the
second quarter of 2006, WPSC's electric utility margin increased
$6.2 million. The increase in electric utility margins was driven by fuel
and purchased power costs that were less than were recovered in rates in
the
second quarter of 2006, compared to no significant over or under collections
in
the second quarter of 2005. Fuel and purchased power costs are expected
to be
greater than what will be recovered in rates in the second half of the
year,
which should negatively impact margins during that period. The rate increase
and
higher wholesale electric sales volumes also contributed to the higher
margin.
Partially offsetting these increases, margin was negatively impacted by
a
decrease in rates related to the refund of a portion of the Kewaunee
nonqualified decommissioning trust fund to customers ($16.2 million of
proceeds received from the liquidation of this fund were refunded to customers
in the second quarter of 2006). Pursuant to regulatory accounting, the
decrease
in margin related to this refund was substantially offset by a corresponding
decrease in operating and maintenance expenses as explained below and,
therefore, did not have a significant impact on earnings. The unfavorable
weather conditions during the cooling season (discussed above), also negatively
impacted margin.
Gas
Utility
Operations
|
|
Three
Months
Ended June 30,
|
|
Gas
Utility
Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
68.0
|
|
$
|
89.8
|
|
|
(24.3
|
%)
|
Purchase
costs
|
|
|
44.2
|
|
|
66.2
|
|
|
(33.2
|
%)
|
Margins
|
|
$
|
23.8
|
|
$
|
23.6
|
|
|
(0.8
|
%)
|
Throughput
in
therms
|
|
|
128.8
|
|
|
162.5
|
|
|
(20.7
|
%)
|
Natural
gas utility
revenue was $68.0 million for the quarter ended June 30, 2006,
compared to $89.8 million for the same quarter in the prior year. The lower
natural gas revenues were driven by a 20.7% decrease in natural gas throughput
volumes, as a result of an 84.6% decrease in natural gas volumes sold to
the
electric utility and a 7.7% decrease in natural gas volumes sold to residential,
and commercial and industrial customers. The decrease in natural gas volumes
sold to the electric utility was driven by a decrease in the need for the
electric utility to run its peaker generation units due to weather that
was 41%
cooler during the cooling season in the second quarter of 2006, compared
to the
same quarter in 2005, as well as higher dispatch of the peaker generation
units
by MISO in 2005 for reliability purposes. The decrease in throughput volumes
to
residential, and commercial and industrial customers was primarily related
to
weather that was 12% warmer during the heating season in the second quarter
of
2006, compared to the same quarter in 2005. These customers are also taking
measures to conserve energy as a result of higher natural gas prices. Partially
offsetting these decreases were an increase in the per-unit cost of natural
gas
and a rate increase at WPSC. Natural gas costs were 5.3% higher (on
a
per-unit
basis)
during the quarter ended June 30, 2006, compared to the same quarter in
2005. Following regulatory practice, changes in the total cost of natural
gas
are passed on to customers through a purchased gas adjustment clause, as
allowed
by the PSCW. In December 2005, the PSCW issued a final order authorizing an
annual natural gas rate increase for WPSC of $7.2 million (1.1%), effective
January 1, 2006. The rate increase was required as a result of
infrastructure improvements necessary to ensure the reliability of the
natural
gas distribution system.
WPSC's
natural gas
utility margin was relatively flat compared to the second quarter of 2005.
Increased margin related to the natural gas rate increase was substantially
offset by a decrease in throughput volumes to higher margin residential,
and
commercial and industrial customers. The decrease in natural gas volumes
sold to
the electric utility did not have a significant impact on WPSC's natural
gas
utility margin as very low margins are recognized on sales to the electric
utility.
Operating
Expenses
|
|
Three
Months
Ended June 30,
|
|
Operating
Expenses (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
81.7
|
|
$
|
100.8
|
|
|
(18.9
|
%)
|
Depreciation
and decommissioning expense
|
|
|
19.9
|
|
|
62.2
|
|
|
(68.0
|
%)
|
Federal
income taxes
|
|
|
10.2
|
|
|
(1.9
|
)
|
|
-
|
|
State
income
taxes
|
|
|
2.5
|
|
|
(1.1
|
)
|
|
-
|
|
Other
Income
|
|
Three
Months
Ended June 30,
|
|
Other
Income
and (Deductions) (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Allowance
for
equity funds used during construction
|
|
$
|
0.2
|
|
$
|
0.5
|
|
|
(60.0
|
%)
|
Other,
net
|
|
|
5.7
|
|
|
42.6
|
|
|
(86.6
|
%)
|
Income
taxes
|
|
|
(1.3
|
)
|
|
(15.9
|
)
|
|
(91.8
|
%)
|
Operating
and
Maintenance Expense
Operating
and
maintenance expenses decreased $19.1 million (18.9%) for the quarter ended
June 30, 2006, compared to the same quarter in 2005. The following items
were the most significant contributors to the change in operating and
maintenance expenses at WPSC:
·
|
WPSC
refunded
$16.2 million of the proceeds received from the liquidation of the
Kewaunee nonqualified decommissioning trust fund to ratepayers
in the
second quarter of 2006. This reduction in revenue was offset
by a related
decrease in operating expenses, due to the partial amortization
of the
regulatory liability recorded for the refund of these proceeds.
|
·
|
Operating
and
maintenance expenses related to the Kewaunee nuclear plant decreased
approximately $10 million due to the sale of this facility in July
2005. The decrease in operating and maintenance expenses related
to
Kewaunee did not have a significant impact on net income as WPSC
is still
purchasing power from this facility in the same amount as its
original
ownership interest. The cost of the purchased power is included
as a
component of utility cost of fuel, natural gas, and purchased
power.
|
·
|
Excluding
Kewaunee, maintenance expenses at WPSC increased $2.0 million in the
second quarter of 2006, compared to the second quarter of 2005.
Planned
maintenance was required on certain combustion turbines in the
second
quarter of 2006, and maintenance expense related to electric
distribution
assets also increased.
|
·
|
Customer
account expenses increased $1.3 million, driven by an increase in
consulting fees related to the implementation of a new software
system.
|
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $42.3 million (68.0%) for the quarter
ended June 30, 2006, compared to the quarter ended June 30, 2005,
driven by approximately $38 million of decommissioning expense that was
recorded in the second quarter of 2005, compared to no decommissioning
expense
recorded in 2006, and a $4.8 million decrease in depreciation expense
resulting from the sale of Kewaunee in July 2005. Subsequent to the sale
of
Kewaunee, decommissioning expense is no longer recorded. In the second
quarter
of 2005, realized gains on decommissioning trust assets were substantially
offset by decommissioning expense pursuant to regulatory practice (see
analysis
of "Federal
Income
Taxes/State Income Taxes/Other Income"
below).
Federal
Income
Taxes/State Income Taxes/Other Income
The
period-over-period change in these categories 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 decrease in
other income related to the realized gains recorded on the nonqualified
decommissioning trust assets in the second quarter of 2005, compared to
no gain
or loss recorded on nonqualified decommissioning trust assets in 2006 due
to the
liquidation of the nonqualified decommissioning trust in the third quarter
of
2005. The nonqualified nuclear decommissioning trust assets were placed
in more
conservative investments in the second quarter of 2005 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 recorded
in
the second quarter of 2005 was offset by an increase in decommissioning
expense
during the same period. 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 in the second quarter
of
2005, 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
|
|
$
|
-
|
|
Six
Months
2006 Compared with Six Months 2005
WPSC
Overview
WPSC's
earnings on
common stock for the six months ended June 30 are shown in the following
table:
WPSC's
Results (Millions)
|
2006
|
2005
|
Change
|
|
|
|
|
Earnings
on
common stock
|
$51.3
|
$58.9
|
(12.9%)
|
WPSC's
earnings on
common stock were $51.3 million for the six months ended June 30,
2006, compared to $58.9 million for the six months ended June 30,
2005. As discussed in more detail below, the following factors impacted
earnings
for the six months ended June 30, 2006, compared to the same period in
2005.
·
|
Electric
utility earnings decreased $5.2 million, from $43.0 million for
the six months ended June 30, 2005 to $37.8 million for the
six months ended June 30, 2006. The decrease in electric utility
earnings was driven by the negative impact unfavorable weather
conditions
and residential customer conservation efforts had on margin,
as well as an
increase in various operating expenses. These items were partially
offset
by the positive impact of fuel and purchased power costs that
were less
than were recovered in rates during the six months ended June
30, 2006,
compared to no significant over or under collections during the
six months
ended June 30, 2005. Fuel and purchased power costs are expected
to be
greater than what will be recovered in the second half of the
year, which
should negatively impact margin during that period. The rate
increase and
higher wholesale electric sales volumes also had a positive impact
on
electric utility earnings.
|
·
|
Natural
gas
utility earnings decreased $3.6 million, from $12.1 million for
the six months ended June 30, 2005, to $8.5 million for the
six months ended June 30, 2006, driven primarily by a decrease in
margin resulting from lower throughput volumes as a result of
warmer
weather during the heating season, customer conservation efforts,
and an
increase in operating and maintenance
expenses.
|
Electric
Utility Operations
|
|
Six
Months
Ended June 30,
|
|
Electric
Utility Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
468.3
|
|
$
|
439.1
|
|
|
6.7
|
%
|
Fuel
and
purchased power
|
|
|
219.8
|
|
|
139.0
|
|
|
58.1
|
%
|
Margin
|
|
$
|
248.5
|
|
$
|
300.1
|
|
|
(17.2
|
%)
|
Sales
in
kilowatt-hours
|
|
|
7,006.2
|
|
|
6,962.5
|
|
|
0.6
|
%
|
Electric
utility
revenue increased $29.2 million (6.7%) for the six months ended
June 30, 2006, compared to the same period in 2005, largely due to an
approved annual electric rate increase for WPSC's Wisconsin retail customers
(discussed above). Electric sales volumes also increased slightly, primarily
related to a 9.7% increase in sales volumes to wholesale customers due
to higher
demand, largely offset by a decrease in sales volumes to residential customers,
driven primarily by unfavorable weather conditions during both the heating
and
cooling seasons in the first half of 2006, compared to the same period
in 2005,
and customer conservation efforts resulting from recent rate increases.
For the
six months ended June 30, 2006, weather during the heating season was 11%
warmer and weather during the cooling season was 41% cooler, compared to
the
same period in 2005.
The
electric
utility margin decreased $51.6 million (17.2%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005,
primarily related to the sale of Kewaunee on July 5, 2005, and the related
power
purchase agreement. Excluding the $48.3 million of fixed payments made to
Dominion Energy Kewaunee during the first six months of 2006, WPSC's electric
utility margin decreased $3.3 million. The margin was negatively impacted
by a decrease in rates related to the refund of a portion of the Kewaunee
nonqualified decommissioning trust fund to customers ($30.0 million of
proceeds received from the liquidation of this fund were refunded to customers
during the six months ended June 30, 2006). Pursuant to regulatory
accounting, the decrease in margin related to this refund was substantially
offset by a corresponding decrease in operating and maintenance expenses
as
explained below and, therefore, did not have a significant impact on earnings.
The unfavorable weather conditions during both the heating and cooling
seasons,
as well as residential customer conservation efforts also negatively impacted
margin. These items were partially offset by the positive impact of fuel
and
purchased power costs that were less than were recovered in rates during
the six
months ended June 30, 2006, compared to no significant over or under collections
during the six months ended June 30, 2005. Fuel and purchased power costs
are
expected to be greater than what will be recovered in the second half of
the
year, which should negatively impact margin during that period. The rate
increase and higher wholesale electric sales volumes also had a positive
impact
on margin. The rate increase was necessary to recover increases in fuel
costs as
well as various operating and maintenance expenses, which are discussed
below.
Gas
Utility
Operations
|
|
Six
Months
Ended June 30,
|
|
Gas
Utility
Results (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
261.0
|
|
$
|
264.4
|
|
|
(1.3
|
%)
|
Purchase
costs
|
|
|
192.4
|
|
|
194.5
|
|
|
(1.1
|
%)
|
Margins
|
|
$
|
68.6
|
|
$
|
69.9
|
|
|
(1.9
|
%)
|
Throughput
in
therms
|
|
|
395.7
|
|
|
471.3
|
|
|
(16.0
|
%)
|
Natural
gas utility
revenue decreased $3.4 million (1.3%) for the six months ended
June 30, 2006, compared to the same period in 2005. The decrease in
natural gas revenues at WPSC was driven by a 16.0% decrease in natural
gas
throughput volumes, primarily related to a 77.1% decrease in natural gas
volumes
sold to the electric utility (resulting from a decrease in the need for
the
electric utility to run its peaker generation units due to weather that
was 41%
cooler during the cooling season in the six months ended June 30, 2006,
compared to the same period in 2005 as well as higher dispatch of the peaker
generation units by MISO in 2005 for reliability purposes), and also by
an 11.2%
decrease in throughput volumes to residential and commercial and industrial
customers due to weather that was 11% warmer during the heating season
in first
half of 2006, compared to the same period in the prior year, and also due
to
customer conservation efforts. Customers are taking measures to conserve
energy
as a result of the high natural gas prices. Partially offsetting these
decreases
was an increase in the per-unit cost of natural gas and the rate increase
at
WPSC. Natural gas costs were 26.8% higher (on a per-unit basis) during
the six
months ended June 30, 2006, compared to the same period in 2005.
The
natural gas
utility margin decreased $1.3 million (1.9%) for the six months ended
June 30, 2006, compared to the six months ended June 30, 2005. A
decrease in throughput volumes to higher margin residential, and commercial
and
industrial customers (discussed above) was partially offset by the rate
increase. The decrease in throughput volumes to the electric utility did
not
have a significant impact on WPSC's natural gas utility margin as very
low
margins are recognized on sales to the electric utility.
Operating
Expenses
|
|
Six
Months
Ended June 30,
|
|
Operating
Expenses (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Operating
and
maintenance expense
|
|
$
|
164.1
|
|
$
|
199.0
|
|
|
(17.5
|
%)
|
Depreciation
and decommissioning expense
|
|
|
39.7
|
|
|
87.3
|
|
|
(54.5
|
%)
|
Federal
income taxes
|
|
|
22.3
|
|
|
15.1
|
|
|
47.7
|
%
|
State
income
taxes
|
|
|
5.3
|
|
|
3.0
|
|
|
76.7
|
%
|
Other
Income
|
|
Six
Months
Ended June 30,
|
|
Other
Income
and (Deductions) (Millions)
|
|
2006
|
|
2005
|
|
Change
|
|
|
|
|
|
|
|
|
|
Allowance
for
equity funds used during construction
|
|
$
|
0.3
|
|
$
|
0.9
|
|
|
(66.7
|
%)
|
Other,
net
|
|
|
8.5
|
|
|
47.6
|
|
|
(82.1
|
%)
|
Income
taxes
|
|
|
(1.7
|
)
|
|
(16.9
|
)
|
|
(89.9
|
%)
|
Operating
and
Maintenance Expense
Operating
and
maintenance expenses decreased $34.9 million (17.5%) for the six months
ended June 30, 2006, compared to the same period in 2005. The following
items were the most significant contributors to the change in operating
and
maintenance expenses at WPSC:
·
|
WPSC
refunded
$30.0 million of the proceeds received from the liquidation of the
Kewaunee nonqualified decommissioning trust fund to ratepayers
during the
six months ended June 30, 2006. This reduction in revenue was offset
by a related decrease in operating expenses, due to the partial
amortization of the regulatory liability recorded for the refund
of this
fund.
|
·
|
Operating
and
maintenance expenses related to the Kewaunee nuclear plant decreased
approximately $22 million due to the sale of this facility in July
2005. The decrease in operating and maintenance expenses related
to
Kewaunee did not have a significant impact on net income as WPSC
is still
purchasing power from this facility in the same amount as its
original
ownership interest. The cost of the power is included as a component
of
utility cost of fuel, natural gas, and purchased power.
|
·
|
Excluding
Kewaunee, maintenance expenses at WPSC increased $3.9 million for the
six months ended June 30, 2006, compared to the same period in 2005.
Planned maintenance was required on certain combustion turbines
in the
first half of 2006, and maintenance expenses related to electric
distribution assets also increased.
|
·
|
Customer
account expenses increased $2.5 million, driven by an increase in
consulting fees related to the implementation of a new software
system.
|
·
|
Write-offs
of
uncollectible customer accounts increased $1.9 million in the first
half of 2006, compared to the same period in 2005, due primarily
to higher
energy costs.
|
·
|
Transmission-related
expenses, and amortization of other previously deferred regulatory
assets
also increased during the six months ended June 30, 2006, compared to
the same period in 2005.
|
Depreciation
and Decommissioning Expense
Depreciation
and
decommissioning expense decreased $47.6 million (54.5%) for the six months
ended June 30, 2006, compared to the six months ended June 30, 2005,
driven by approximately $41 million of decommissioning expense that was
recorded during the six months ended June 30, 2005, compared to no
decommissioning expense recorded in 2006, and a $9.5 million decrease in
depreciation expense resulting from the sale of Kewaunee in July 2005.
Subsequent to the sale of Kewaunee, decommissioning expense is no longer
recorded. In 2005, realized gains on decommissioning trust assets were
substantially offset by decommissioning expense pursuant to regulatory
practice
(see analysis of "Federal
Income
Taxes/State Income Taxes/Other Income"
below). Continued
capital investment at WPSC also partially offset the overall decrease in
depreciation and decommissioning expense.
Federal
Income
Taxes/State Income Taxes/Other Income
The
period-over-period change in these categories was primarily related to
the
realized gains recognized on the nonqualified decommissioning trust assets
in
the second quarter of 2005. Approximately $41 million of the decrease in
other income related to the realized gains recorded on the nonqualified
decommissioning trust assets during the six months ended June 30, 2005,
compared to no gain or loss recorded on nonqualified decommissioning trust
assets in 2006 due to the liquidation of the nonqualified decommissioning
trust
in the third quarter of 2005. The nonqualified nuclear decommissioning
trust
assets were placed in more conservative investments in the second quarter
of
2005 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 recorded in the second quarter of 2005 was offset by
an
increase in decommissioning expense during the same period. 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
in 2005,
as summarized in the table below.
(Millions)
|
|
Income/(Expense)
|
|
|
|
|
|
Depreciation
and decommissioning expense
|
|
$
|
(41
|
)
|
Federal
income taxes
|
|
|
13
|
|
State
income
taxes
|
|
|
2
|
|
Other,
net
|
|
|
41
|
|
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-term 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 "Liquidity
and
Capital Resources - WPS Resources,"
for more
information).
Operating
Cash Flows
During
the six
months ended June 30, 2006, net cash provided by operating activities was
$138.1 million, compared to $154.8 million for the same period in
2005. The $16.7 million decrease resulted from a $35.7 million
decrease in cash provided from changes in working capital, partially offset
by
an increase in net income adjusted for non-cash items. Changes in working
capital requirements were a function of increased energy prices.
Investing
Cash Flows
Net
cash used for
investing activities was $135.6 million during the six months ended
June 30, 2006, compared to $184.2 million during the six months
ended June 30, 2005. The decrease in cash used for investing activities was
driven by a decrease in capital expenditures, primarily related to the
construction of Weston 4 as explained below.
Capital
Expenditures
Capital
expenditures by business segment for the six months ended June 30 are as
follows:
(Millions)
|
|
2006
|
|
2005
|
|
Electric
utility
|
|
$
|
129.5
|
|
$
|
168.2
|
|
Gas
utility
|
|
|
15.0
|
|
|
14.2
|
|
Other
|
|
|
-
|
|
|
0.3
|
|
WPSC
consolidated
|
|
$
|
144.5
|
|
$
|
182.7
|
|
The
decrease in
capital expenditures at the electric utility for the six months ended
June 30, 2006, as compared to the same period in 2005 is mainly due to
lower capital expenditures associated with the construction of Weston 4,
as a
result of the sale of a 30% interest in the project to DPC in the fourth
quarter
of 2005. Commercial operation for Weston 4 is still expected to occur in
June 2008.
Financing
Cash Flows
Net
cash used for
financing activities was $4.3 million during the six months ended
June 30, 2006, compared to $28.2 million provided by financing
activities for the same period in 2005. The change was driven by a decrease
in
capital expenditures during the six months ended June 30, 2006, compared to
the same period in 2005.
As
prescribed by the PSCW, 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
June 30, 2006
(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
|
|
$
|
719.1
|
|
$
|
13.5
|
|
$
|
54.1
|
|
$
|
54.1
|
|
$
|
597.4
|
|
Operating
lease obligations
|
|
|
12.5
|
|
|
1.6
|
|
|
4.6
|
|
|
2.8
|
|
|
3.5
|
|
Commodity
purchase obligations
|
|
|
1,979.5
|
|
|
161.5
|
|
|
585.5
|
|
|
498.8
|
|
|
733.7
|
|
Purchase
orders
|
|
|
411.7
|
|
|
288.8
|
|
|
122.8
|
|
|
0.1
|
|
|
-
|
|
Other
|
|
|
368.4
|
|
|
40.6
|
|
|
61.3
|
|
|
38.9
|
|
|
227.6
|
|
Total
contractual cash obligations
|
|
$
|
3,491.2
|
|
$
|
506.0
|
|
$
|
828.3
|
|
$
|
594.7
|
|
$
|
1,562.2
|
|
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.
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.
The sale
of a 30% interest in Weston 4 to DPC was completed in November 2005, but
WPSC
retains the legal obligation to initially remit payment to third parties
for
100% of all construction costs incurred, 30% of which will subsequently
be
billed to DPC. Other mainly represents expected pension and postretirement
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
Asset
Management Strategy
See
"Liquidity
and
Capital Resources - WPS Resources,"
for detailed
information on WPS Resources' asset management strategy.
Regulatory
Matters and Rate Trends
See
"Liquidity
and
Capital Resources - WPS Resources,"
for detailed
information on regulatory matters and rate trends.
Energy
Efficiency and Renewables Act
See
"Liquidity
and
Capital Resources - WPS Resources,"
for detailed
information on the Energy Efficiency and Renewables Act.
Seams
Elimination Charge Adjustment
See
"Liquidity
and
Capital Resources - WPS Resources,"
for detailed
information on the Seams Elimination Charge Adjustment.
Income
Taxes
See
"Liquidity
and
Capital Resources
- WPS Resources,"
for detailed
information on income tax matters applicable to WPSC.
Environmental
See
Note 11,
"Commitments
and
Contingencies,"
in the Condensed
Notes to Financial Statements for a detailed discussion of environmental
considerations.
Midwest
Independent Transmission System Operator
See
"Liquidity
and
Capital Resources
- WPS Resources,"
for detailed
information on MISO.
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, 2005, are still current and that
there have been no significant changes.