MINNEAPOLIS--(BUSINESS WIRE)--
Xcel Energy Inc. (NYSE: XEL) today reported first quarter 2009 earnings
of $174 million, or $0.38 per diluted share, compared with $153 million,
or $0.35 per diluted share, in 2008.
Higher first quarter 2009 earnings were primarily due to improved
financial performance at Southwestern Public Service Company, interim
electric rates in Minnesota and improved fuel cost recovery in
Wisconsin, partially offset by a decline in earnings at Public Service
Company of Colorado.
"We are pleased to report solid earnings, reflecting the continued
execution of our strategy to invest in our core utility businesses and
earn a reasonable return on our invested capital," said Richard C.
Kelly, chairman, president and chief executive officer. "Despite the
challenging economic environment our business plan remains on track and
we are reaffirming our 2009 earnings guidance of $1.45 to $1.55 per
share."
At 10 a.m. CDT today, Xcel Energy will host a conference call to review
first quarter financial results. To participate in the call, please dial
in five to 10 minutes prior to the start and follow the operator's
instructions.
US Dial-In: (800) 218-8862
International Dial-In: (303) 262-2052
The conference call also will be simultaneously broadcast and archived
on Xcel Energy's Web site at www.xcelenergy.com.
To access the presentation, click on Investor Information. If you are
unable to participate in the live event, the call will be available for
replay from 12:00 p.m.CDT on April 30 through 11:59 p.m. CDT on May 1.
Replay Numbers
US Dial-In: (800) 405-2236
International Dial-In: (303) 590-3000
Access Code: 11129075#
Except for the historical statements contained in this release, the
matters discussed herein, including our 2009 full year EPS guidance and
assumptions, are forward-looking statements that are subject to certain
risks, uncertainties and assumptions. Such forward-looking statements
are intended to be identified in this document by the words
"anticipate," "believe," "estimate," "expect," "intend," "may,"
"objective," "outlook," "plan," "project," "possible," "potential,"
"should" and similar expressions. Actual results may vary materially.
Forward-looking statements speak only as of the date they are made, and
we do not undertake any obligation to update them to reflect changes
that occur after that date. Factors that could cause actual results to
differ materially include, but are not limited to: general economic
conditions, including the availability of credit and its impact on
capital expenditures and the ability of Xcel Energy and its subsidiaries
to obtain financing on favorable terms; business conditions in the
energy industry; actions of credit rating agencies; competitive factors,
including the extent and timing of the entry of additional competition
in the markets served by Xcel Energy and its subsidiaries; unusual
weather; effects of geopolitical events, including war and acts of
terrorism; state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on
rates or have an impact on asset operation or ownership; structures that
affect the speed and degree to which competition enters the electric and
natural gas markets; costs and other effects of legal and administrative
proceedings, settlements, investigations and claims; actions of
accounting regulatory bodies; and the other risk factors listed from
time to time by Xcel Energy in reports filed with the Securities and
Exchange Commission (SEC), including Risk Factors in Item 1A and Exhibit
99.01 of Xcel Energy's Annual Report on Form 10-K for the year ended
Dec. 31, 2008.
This information is not given in connection with any sale, offer for
sale or offer to buy any security.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31,
(Amounts in Thousands, Except Per Share Data) 2009 2008
Operating revenues
Electric $ 1,886,557 $ 1,973,314
Natural gas 788,676 1,034,127
Other 20,309 20,947
Total operating revenues 2,695,542 3,028,388
Operating expenses
Electric fuel and purchased power 924,748 1,088,080
Cost of natural gas sold and transported 591,765 823,127
Cost of sales -- other 5,366 5,453
Other operating and maintenance expenses 471,894 461,020
Conservation and demand side management program 45,219 35,570
expenses
Depreciation and amortization 208,715 205,607
Taxes (other than income taxes) 77,038 79,413
Total operating expenses 2,324,745 2,698,270
Operating income 370,797 330,118
Interest and other income, net 2,352 8,374
Allowance for funds used during construction -- 18,227 14,220
equity
Interest charges and financing costs
Interest charges -- (includes other financing
costs of $5,038 and $4,991,
respectively) 141,803 132,171
Allowance for funds used during construction -- (10,228 ) (9,527 )
debt
Total interest charges and financing costs 131,575 122,644
Income from continuing operations before income 259,801 230,068
taxes and equity earnings
Income taxes 87,125 76,584
Equity earnings of unconsolidated subsidiaries 3,142 510
Income from continuing operations 175,818 153,994
Loss from discontinued operations, net of tax (1,751 ) (877 )
Net income 174,067 153,117
Dividend requirements on preferred stock 1,060 1,060
Earnings available to common shareholders $ 173,007 $ 152,057
Weighted average common shares outstanding:
Basic 455,192 429,563
Diluted 455,952 434,853
Earnings per average common share:
Basic $ 0.38 $ 0.35
Diluted 0.38 0.35
Cash dividends declared per common share 0.24 0.23
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Release (Unaudited)
Due to the seasonality of Xcel Energy's operating results, quarterly
financial results are not an appropriate base from which to project
annual results.
Note 1. Earnings per Share
Summary
The following table summarizes the diluted earnings per share
contributions of Xcel Energy's operating companies:
Three Months Ended March 31,
Diluted earnings (loss) per share 2009 2008
Public Service Company of Colorado (PSCo) $ 0.17 $ 0.22
NSP-Minnesota 0.17 0.15
NSP-Wisconsin 0.04 0.03
Southwestern Public Service Company (SPS) 0.02 (0.01 )
Equity earnings of unconsolidated subsidiaries 0.01 -
(WYCO)
Regulated utility -- continuing operations (Note 0.41 0.39
2)
Holding company and other costs (0.03 ) (0.04 )
Total GAAP and ongoing1diluted earnings per share $ 0.38 $ 0.35
The following table summarizes significant components contributing to
the changes in the first quarter of 2009 earnings per share compared
with 2008, which are discussed in more detail later in the release.
Three Months
Ended March 31,
2008 GAAP and ongoing1diluted earnings per share $ 0.35
Components of change -- 2009 vs. 2008
Higher electric margins 0.11
Higher allowance for funds used during construction -- equity 0.01
Higher operating and maintenance expenses (0.02 )
Lower natural gas margins (0.02 )
Dilution from DRIP, benefit plan and the 2008 common equity (0.02 )
issuance
Higher interest expenses (0.01 )
Higher conservation and demand side management program expenses (0.01 )
Other (0.01 )
2009 GAAP and ongoing1diluted earnings per share $ 0.38
1 Ongoing earnings exclude the impact related to the
Corporate Owned Life Insurance (COLI) program. During 2007, Xcel Energy
resolved a dispute with the IRS regarding its COLI program. For the
first quarter of 2009 and 2008, income was not materially affected by
the termination of the COLI program, and there was no effect on the
first quarter 2009 earnings per share.
Note 2. Regulated Utility
Results -- Continuing Operations
Estimated Impact of Temperature Changes on Regulated Earnings --
The following table summarizes the estimated impact on earnings per
share of temperature variations on first quarter results, compared with
sales under normal weather conditions.
Three Months Ended March 31,
2009 vs. 2008 vs. 2009 vs.
Normal Normal 2008
Retail electric $ 0.00 $ 0.01 $ (0.01 )
Firm natural gas 0.00 0.01 (0.01 )
Total $ 0.00 $ 0.02 $ (0.02 )
Sales Growth -- The following table summarizes Xcel
Energy's sales decline for actual and weather-normalized sales for the
three-month period, excluding the impact of the 2008 leap year.
Three Months Ended March 31,
Actual Normalized
Electric residential (2.4) % (0.7) %
Electric commercial and industrial (1.8) (1.4)
Total retail electric sales (2.0) (1.2)
Firm natural gas sales (9.9) (1.1)
Electric -- The following tables detail the electric
revenues and margin:
Three Months Ended March 31,
(Millions of dollars) 2009 2008
Electric revenues $ 1,887 $ 1,973
Electric fuel and purchased power (925 ) (1,088 )
Electric margin $ 962 $ 885
The following table summarizes the components of the changes in electric
margin for the three months ended March 31:
Three Months
Ended March 31,
2009 vs. 2008
(Millions of dollars)
Retail rate increases (Minnesota interim, Texas interim, $ 45
Wisconsin and New Mexico)
Conservation and demand side management revenue 17
SPS 2008 fuel cost allocation regulatory accruals 12
Non-fuel riders 10
NSP-Wisconsin fuel recovery 9
Metropolitan Emissions Reduction Project (MERP) rider 5
Purchased capacity costs (18 )
Estimated impact of weather (6 )
Retail sales decline (excluding weather impact) (2 )
Other, net 5
Total increase in electric margin $ 77
Xcel Energy has experienced a decline in megawatt hours (MwH) sales,
particularly in the commercial and industrial customer class. However,
since these customers generally pay a demand fee, the impact of the
lower MwH sales was mitigated to a certain degree.
Natural Gas -- The following table details the changes in
natural gas revenues and margin. The cost of natural gas tends to vary
with changing sales requirements and the cost of natural gas purchases.
However, due to purchased natural gas cost recovery mechanisms for sales
to retail customers, fluctuations in the cost of natural gas have little
effect on natural gas margin.
Three Months Ended March 31,
(Millions of dollars) 2009 2008
Natural gas revenues $ 789 $ 1,034
Cost of natural gas sold and transported (592) (823)
Natural gas margin $ 197 $ 211
The following table summarizes the components of the changes in natural
gas margin for the three months ended March 31:
Three Months
(Millions of dollars) Ended March 31,
2009 vs. 2008
Estimated impact of weather $ (10 )
Sales decline (excluding weather impact) (1 )
Other, net (3 )
Total decrease in natural gas margin $ (14 )
Other Operating and Maintenance Expenses -- Other operating
and maintenance expenses for the first quarter of 2009 increased by
approximately $10.9 million, or 2.4 percent, compared with 2008. The
following table summarizes the changes in other operating and
maintenance expenses for the three months ended March 31, 2009:
Three Months
(Millions of dollars) Ended March 31,
2009 vs. 2008
Higher employee benefit costs $ 16
Higher nuclear plant operation costs 10
Higher labor costs 5
Nuclear outage costs, net of deferral (12 )
Lower consulting costs (4 )
Other, net (4 )
Total increase in other operating and maintenance expenses $ 11
Higher employee benefits costs are primarily attributable to increased
pension costs, in part, related to market losses on retirement benefit
plan assets as well as higher employee medical plan costs. The increase
in nuclear plant operation costs is driven primarily by an increase in
security costs and regulatory fees, resulting from new Nuclear
Regulatory Commission (NRC) requirements. The decline in nuclear outage
expense is due to the commissions approval of the change the nuclear
refueling outage recovery method from the direct expense method to the
deferral and amortization method in the third quarter of 2008.
Depreciation and Amortization -- Depreciation and
amortization expenses increased by approximately $3.1 million, or 1.5
percent, for the first quarter of 2009, compared with 2008. The increase
is primarily due to normal system expansion from investments in our
utility operations.
Conservation and Demand Side Management (DSM) --
Conservation and DSM expenses increased approximately $9.6 million, or
27.1 percent for the first quarter of 2009, compared with 2008. The
higher expense is attributable to the expansion of programs and
regulatory commitments. Conservation and DSM program expenses are
generally recovered through riders in our major jurisdictions or through
general rate cases.
Allowance for Funds Used During Construction, Equity and Debt
(AFDC) -- AFDC increased by approximately $4.7 million, or 19.8
percent, for the first quarter of 2009, compared with 2008. The increase
was due primarily to the construction of Comanche 3, a power facility
located in Colorado which is nearing completion, and other construction
projects.
Interest Charges -- Interest charges increased by
approximately $9.6 million, or 7.3 percent, for the first quarter of
2009, compared with 2008. The increase was primarily the result
of increased debt levels to fund new capital investments.
Income Taxes -- Income taxes for continuing operations
increased by $10.5 million for the first quarter of 2009, compared with
2008. The increase in income tax expense was primarily due to an
increase in pretax income. The effective tax rate for continuing
operations was 33.5 percent for the first quarter of 2009, compared with
33.2 percent for 2008.
Equity Earnings of Unconsolidated Subsidiaries -- Equity
earnings of unconsolidated subsidiaries increased by $2.6 million for
the first quarter of 2009, compared with 2008, primarily due to
increased earnings from the equity investment in WYCO Development LLC
(WYCO) as a result of the High Plains gas pipeline commencing operations
in late 2008.
Note 3. Xcel Energy Capital Structure
and Financing
Following is the capital structure of Xcel Energy at March 31, 2009:
Percentage of
Balance at Total
(Billions of dollars) March 31, 2009 Capitalization
Current portion of long-term debt $ 0.5 3 %
Short-term debt 0.4 3
Long-term debt 7.7 49
Total debt 8.6 55
Preferred equity 0.1 0
Common equity 7.0 45
Total equity 7.1 45
Total capitalization $ 15.7 100 %
During the first quarter of 2009, Xcel Energy repaid the following
securities:
-- Called the NSP-Wisconsin 7.375 percent $65 million first mortgage bonds,
due Dec. 1, 2026.
-- Retired the SPS 6.2 percent $100 million of unsecured senior A notes,
due March 1, 2009.
These debt repayments were funded by existing cash resources primarily
from bonds issued in 2008.
During 2009, Xcel Energy plans to issue debt securities to refinance
retiring maturities, reduce short-term debt, fund construction programs
and for other general corporate purposes. Current debt financing plans
include the following:
-- Issuing approximately $400 million of first mortgage bonds at
NSP-Minnesota in the summer.
-- Issuing approximately $400 million of first mortgage bonds at PSCo in
late spring or early summer.
Financing plans are subject to change, depending on capital
expenditures, internal cash generation, market conditions and other
factors.
Note 4. Liquidity
Xcel Energy expects to meet future financing requirements by
periodically issuing short-term debt, long-term debt, common stock,
preferred securities and hybrid securities to maintain desired
capitalization ratios.
Short-Term Funding Sources -- Xcel Energy uses a number of
sources to fulfill short-term funding needs, including operating cash
flow, notes payable, commercial paper and bank lines of credit. The
amount and timing of short-term funding needs depend in large part on
financing needs for construction expenditures, working capital and
dividend payments.
General -- As a result of volatile conditions in global
capital markets, general liquidity in short-term credit markets has been
periodically constrained. Xcel Energy has maintained access to
short-term liquidity through the A2/P2 commercial paper market and
utilization of direct borrowing on committed credit agreements. In
addition, Xcel Energy's overall liquidity was strengthened by the
issuance of long-term debt, equity and hybrid securities completed
during 2008. The proceeds from these financings were used to refinance
maturing debt obligations, repay short-term debt and general corporate
purposes.
Commercial Paper -- Xcel Energy, NSP-Minnesota, PSCo and
SPS each have individual commercial paper programs. The authorized
levels for these commercial paper programs are:
-- $800 million for Xcel Energy;
-- $500 million for NSP-Minnesota;
-- $700 million for PSCo; and
-- $250 million for SPS.
Xcel Energy and Utility Subsidiary Credit Facilities -- As
of April 22, 2009, Xcel Energy had the following credit facilities
available to meet its liquidity needs:
(Millions of
Dollars)
Company Facility Drawn1 Available Cash Liquidity Maturity
NSP-Minnesota $ 482 $ 6 $ 476 $ 90 $ 566 December 2011
PSCo 675 5 670 1 671 December 2011
SPS 248 10 238 166 404 December 2011
Xcel Energy - 772 401 371 - 371 December 2011
Holding Company
NSP-Wisconsin2 - - - 24 24
Total $ 2,177 $ 422 $ 1,755 $ 281 $ 2,036
1 Includes direct borrowings, outstanding commercial paper
and letters of credit.
2 NSP-Wisconsin does not have a separate credit facility;
however, it has a borrowing agreement with NSP-Minnesota.
Credit Agency Ratings --The access and cost of short-term
and long-term borrowings are affected by regulatory actions, capital
markets conditions and credit agency ratings. The following ratings
reflect the views of Moody's Investor Services, Inc. (Moody's),
Standard & Poor's Ratings Services (S&P's), and Fitch Ratings (Fitch). A
security rating is not a recommendation to buy, sell or hold securities
and is subject to revision or withdrawal at any time by the rating
agency. As of April 22, 2009, the following represents the credit
ratings assigned to various Xcel Energy companies.
Company Credit Type Moody's S & P's Fitch
Xcel Energy Senior Unsecured Debt Baa1 BBB BBB+
Xcel Energy Commercial Paper P-2 A-2 F2
NSP-Minnesota Senior Unsecured Debt A3 BBB+ A
NSP-Minnesota Senior Secured Debt A2 A A+
NSP-Minnesota Commercial Paper P-2 A-2 F1
NSP-Wisconsin Senior Unsecured Debt A3 A- A
NSP-Wisconsin Senior Secured Debt A2 A A+
PSCo Senior Unsecured Debt Baa1 BBB+ A-
PSCo Senior Secured Debt A3 A A
PSCo Commercial Paper P-2 A-2 F2
SPS Senior Unsecured Debt Baa1 BBB+ BBB+
SPS Commercial Paper P-2 A-2 F2
Note 5. Rates and Regulation
CapX 2020 Transmission Project -- In
August 2007, NSP-Minnesota and Great River Energy (on behalf of eight
other regional transmission providers) filed a certificate of need
application, for three 345 KV transmission lines, as part of the CapX
2020 project. The project to build the three lines includes construction
of approximately 600 miles of new facilities at a cost of approximately
$1.7 billion, with construction to be completed in phases. The cost of
the project to NSP-Minnesota and NSP-Wisconsin is estimated to be
approximately $900 million. These cost estimates will be revised after
the regulatory process is completed.
On April 16, 2009, the MPUC granted a certificate of need to construct
three 345 kilovolt electric transmission lines in Minnesota. The MPUC
also included a condition regarding guaranteeing a portion of the
capacity of the Brookings, SD-Hampton, Minn., line for renewable energy.
Applications for route permits are currently under state review or in
development, and decisions are expected in 2010. Similar regulatory
processes will be pursued for segments of the three 345 kilovolt lines
in Wisconsin, North Dakota and South Dakota. Permits in those states
will be filed in 2009 with decisions expected in 2010. Federal permit
applications will be filed in 2009.
NSP-Minnesota - Minnesota Electric Rate Case -- On Nov. 3,
2008, NSP-Minnesota, filed a request with the Minnesota Public Utilities
Commission (MPUC) to increase Minnesota electric rates by $156 million
annually, or 6.05 percent. The request is based on a 2009 forecast test
year, an electric rate base of $4.1 billion, a requested return on
equity (ROE) of 11.00 percent, and an equity ratio of 52.5 percent.
In December 2008, the MPUC approved an interim rate increase, subject to
refund, of $132 million, or 5.12 percent, effective Jan. 2, 2009. The
primary difference between interim rate levels approved and
NSP-Minnesota's request of $156 million is due to a previously
authorized ROE of 10.54 percent and NSP-Minnesota's requested ROE of
11.00 percent.
On April 7, 2009, intervenors submitted direct testimony. The Office of
Energy Security (OES) recommended a revenue increase of $72 million,
based on a ROE of 10.88 percent and an equity ratio of 52.5 percent. In
addition, the OES recommendation reflected the following adjustments:
-- Recognition of a 10 year life extension of the Prairie Island facility,
resulting in a decrease of approximately $40 million in depreciation and
decommissioning expenses and rejection of our proposed nuclear rate
stability plan. These adjustments reduce NSP-Minnesota's rate request
while at the same time reducing expense accruals by $40 million.
-- An adjustment for increased sales, which reduced the request by $12.3
million, a $7 million reduction in short-term capacity expenses, a
decrease in overall salaries of $4.8 million, a decrease in vegetation
management costs of $2.2 million and chemical commodity cost decreases
of $1.6 million.
The Office of the Attorney General (OAG) recommended recognition of
depreciation and decommissioning cost decreases resulting from the
Prairie Island life extension in the current proceeding and rejection of
the proposed nuclear rate stability plan. However, the OAG did not
recommend a specific reduction in revenue requirements. The OAG also
proposed a fuel clause adjustment (FCA) incentive through a 3 percent
cap on base fuel costs and requested that any approved increase in rates
be applied equally to all classes of customers.
A final decision from the MPUC is expected in the third quarter of 2009.
The following procedural schedule has been established:
-- NSP-Minnesota rebuttal testimony on May 5, 2009;
-- Intervenor surrebuttal testimony on May 26, 2009; and
-- Evidentiary hearings are scheduled for June 2-9, 2009.
PSCo - Colorado Electric Rate Case -- On Nov. 14, 2008,
PSCo, filed with Colorado Public Utilities Commission (CPUC) a request
to increase Colorado electric rates by approximately $174.7 million, or
7.4 percent. The rate filing is based on a 2009 forecast test-year, an
electric rate base of approximately $4.15 billion, a requested ROE of
11.0 percent and an equity ratio of 58.08 percent. PSCo's request
included a return of approximately $40 million for construction work in
progress (CWIP) associated with incremental expenditures on the Comanche
3 coal plant since Jan. 1, 2007, based on a 2004 settlement agreement. A
return on Comanche 3 CWIP, prior to Jan. 1, 2007, is included in
existing rates. Under the settlement agreement, PSCo does not record
AFDC income for the months this return is actually received from
customers.
On Feb. 13, 2009, parties filed testimony in the case. On March 20,
2009, PSCo filed rebuttal testimony and revised their request to a rate
increase of $159.3 million.
On April 10, 2009, intervenors filed surrebuttal testimony. The CPUC
staff increased their revenue deficiency to $133 million based on a
forward test-year, an authorized ROE of 10.71 percent and an equity
ratio of 58 percent. The CPUC Staff also recommended a phase-in of rates
with $70 million effective July 2009 and the remainder to be effective
in January 2010. The Office of Consumer Council (OCC) recommended an $11
million rate increase based on a historic year and an authorized ROE of
10 percent.
On April 22, 2009, a settlement agreement with CPUC staff, the Colorado
Office of Consumer Counsel, Colorado Energy Consumers, CF&I Steel, LP,
Wal-Mart Stores, Inc., Sam's West, Inc., and Energy Outreach Colorado,
was filed with the CPUC.
The settlement provides for an overall $112.2 million increase in base
rates, but does not provide for the specific resolution of many of the
disputed issues such as return on equity and capital structure. However,
the settlement provides that incremental CWIP not included in existing
rates for Comanche 3 is removed from rate base and that PSCo is allowed
to continue to record AFDC income on this balance until Comanche 3 is
placed into service. The settlement in pending CPUC approval and a final
decision is expected in the summer of 2009. The settlement provides that
parties support new rates to be effective on July 1, 2009.
SPS - Texas Electric Retail Rate Case -- In June 2008, SPS
filed a rate case with Public Utility Commission of Texas (PUCT),
seeking an annual rate increase of approximately $61.3 million, or
approximately 5.9 percent. This reflected a base revenue increase to
$94.4 million and a decline in fuel and purchased power revenue of $33.1
million, primarily due to fuel savings from the Lea Power Partners LLC
(LPP) purchase power agreement.
The rate filing was based on a 2007 test-year adjusted for known and
measurable changes, a requested ROE of 11.25 percent, an electric rate
base of $989.4 million and an equity ratio of 51.0 percent. Interim
rates of $18 million for costs associated with the LPP purchase power
agreement went into effect in September 2008.
In January 2009, we reached an agreement with intervenors, which
provided for base rate increase of $57.4 million. Key terms include the
following:
-- An adjustment, which reduced depreciation expense by $5.6 million from
currently authorized rates;
-- Allows SPS to implement the transmission cost recovery factor in 2009;
-- Precludes SPS from filing to seek any other change in base rates until
Feb. 15, 2010; and
-- Resolves all fuel reconciliation issues for 2006-07 with one adjustment
of $0.6 million, related to the sharing of certain wholesale revenue.
The overall settlement is now pending final PUCT approval and the
settlement rates are in effect subject to this final approval.
SPS - New Mexico Retail Electric Rate Case -- On Dec. 18,
2008, SPS filed with the New Mexico Public Regulation Commission (NMPRC)
a request to increase electric rates by approximately $24.6 million, or
6.2 percent. The request is based on a historic test-year (split year
based on year-ending June 30, 2008), an electric rate base of $321
million, an equity ratio of 50 percent and a requested ROE of 12
percent. SPS also requested interim rates of $7.6 million to recover
capacity costs of the Lea Power facility, which became operational in
September 2008.
On March 26, 2009, the NMPRC approved a partial stipulated settlement
between the parties that allows SPS to recover approximately $5.7
million of interim rates, effective May 1, 2009, through an LPP cost
rider until the final rates from the remainder of the case are effective.
In April 2009, the parties reached an agreement in principle on key
issues such as the amount of the rate increase and the earliest date
that SPS can file its next base rate case, subject to a force majeure
provision. The parties are working out the details to resolve other
issues before a settlement agreement can be concluded, filed with the
NMPRC and disclosed publicly. SPS expects to file the settlement
documents by the end of May 2009.
A final decision is expected later this year.
SPS 2008 Wholesale Rate Case -- In
March 2008, SPS filed a wholesale electric rate case seeking an annual
revenue increase of $14.9 million or an overall 5.14 percent increase,
based on 12.20 percent requested ROE. Four New Mexico Cooperatives filed
a motion for dismissal and protest in April 2008.
On May 30, 2008, the Federal Energy Regulatory Commission (FERC)
conditionally accepted and suspended the rates and established hearing
and settlement procedures. The FERC granted a one-day suspension of
rates instead of 180 days. The proposed base rates of $9.9 million,
based on a 10.25 percent ROE and a 12-coincident peak demand allocator,
became effective in September 2008, subject to refund.
The parties reached a settlement in principle and an uncontested
settlement offer was filed with the FERC on April 23, 2009. As a result
of the settlement, SPS will receive an annual revenue increase of
approximately $9.6 million or an overall percentage increase of 3.3
percent. SPS expects the FERC to approve the uncontested settlement.
Note 6. Xcel Energy Earnings
Guidance
Xcel Energy's 2009 earnings guidance is $1.45 to $1.55 per share. Key
assumptions are detailed below:
-- Normal weather patterns are experienced for the remainder of the year.
-- Reasonable regulatory outcomes in the Minnesota electric rate case, the
Colorado electric rate case, the Texas electric rate case, the New
Mexico electric rate case, and other rate cases that may be filed during
the year.
-- Various riders, associated with MERP, Minnesota and Colorado
transmission and Minnesota renewable energy, are expected to increase
revenue by approximately $50 million to $60 million over 2008 levels.
-- Weather adjusted electric retail sales decline by approximately 1
percent.
-- Weather adjusted retail firm natural gas sales decline by approximately
1 percent.
-- Capacity costs are projected to increase approximately $45 million over
2008 levels. Capacity costs at PSCo are recovered under the purchased
capacity cost adjustment.
-- Operating and maintenance expenses are projected to increase:
o Nuclear (including outage amortization) - $55 million
o Pension and medical - $25 million
o Other (including incentive compensation) - $55 million to $105 million
-- Depreciation and amortization expense is projected to increase
approximately $50 million to $60 million over 2008.
-- Interest expense increases approximately $15 million to $25 million over
2008 levels.
-- Allowance for funds used during construction - equity to remain
consistent with 2008 levels.
-- An effective tax rate for continuing operations of approximately 33
percent to 35 percent.
-- Average common stock and equivalents of approximately 457 million
shares.
XCEL ENERGY INC. AND SUBSIDIARIES
UNAUDITED EARNINGS RELEASE SUMMARY
All amounts in thousands, except earnings per share
Three Months Ended March 31, 2009 2008
Operating revenues:
Electric and natural gas utility and trading $ 2,675,233 $ 3,007,441
revenues
Other 20,309 20,947
Total operating revenues 2,695,542 3,028,388
Income from continuing operations 175,818 153,994
Loss from discontinued operations (1,751 ) (877 )
Net income 174,067 153,117
Earnings available to common shareholders 173,007 152,057
Weighted average diluted common shares outstanding 455,952 434,853
Components of Earnings per Share -- Diluted
Regulated utility -- continuing operations $ 0.41 $ 0.39
Holding company and other costs (0.03 ) (0.04 )
Total earnings per share $ 0.38 $ 0.35
Book value per share $ 15.48 $ 14.77
Source: Xcel Energy Inc.
Contact: Xcel Energy Inc.
Paul Johnson, 612-215-4535
Managing Director, Investor Relations and Assistant Treasurer
or
Jack Nielsen, 612-215-4559
Director, Investor Relations
or
Cindy Hoffman, 612-215-4536
Senior Investor Relations Analyst
or
News media inquiries only:
Xcel Energy media relations, 612-215-5300
www.xcelenergy.com