As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 4/30/09  Xcel Energy Inc                   8-K:2,9     4/30/09    2:378K                                   Merrill Corp-MD/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 8-K         Current Report                                      HTML     18K 
 2: EX-99.01    Miscellaneous Exhibit                               HTML    241K 

Exhibit 99.01

 

 

	414 Nicollet Mall
	Minneapolis, MN 55401

 

April 30, 2009

 

INVESTOR RELATIONS EARNINGS RELEASE

 

FIRST QUARTER 2009 EARNINGS

 

·                  GAAP (generally accepted accounting principles) first quarter earnings per share were $0.38 in 2009, compared with $0.35 per share in 2008.

·                  Xcel Energy reaffirms its 2009 earnings guidance of $1.45 to $1.55 per diluted share.

 

MINNEAPOLIS – 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#

 

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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 (WYCO)		0.01			—
Regulated utility — continuing operations (Note 2)		0.41			0.39
Holding company and other costs		(0.03		)	(0.04		)
Total GAAP and ongoing(1) diluted 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 ongoing(1) diluted 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 issuance		(0.02		)
Higher interest expenses		(0.01		)
Higher conservation and demand side management program expenses		(0.01		)
Other		(0.01		)
2009 GAAP and ongoing(1) diluted 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.

 

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		Three Months Ended March 31,
		2009 vs. Normal			2008 vs. Normal			2009 vs. 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:

 

(Millions of dollars)		Three Months Ended March 31, 2009 vs. 2008
Retail rate increases (Minnesota interim, Texas interim, Wisconsin and New Mexico)		$	45
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.

 

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		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:

 

(Millions of dollars)		Three Months 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:

 

(Millions of dollars)		Three Months 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 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.

 

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Note 3. Xcel Energy Capital Structure and Financing

 

Following is the capital structure of Xcel Energy at March 31, 2009:

 

(Billions of dollars)		Balance at March 31, 2009			Percentage of Total 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.

 

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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			Drawn(1)			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 Holding Company		772			401			371			—			371			December 2011
NSP-Wisconsin(2)		—			—			—			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

 

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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.

 

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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.

 

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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:

·                  Nuclear (including outage amortization) - $55 million

·                  Pension and medical - $25 million

·                  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.

 

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