UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): March 31, 2009
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
| Oregon | 1-5532-99 | 93-0256820 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) | (I.R.S. Employer Identification No.) |
121 SW Salmon Street, Portland, Oregon 97204
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (503) 464-8000
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 7.01 | Regulation FD Disclosure. |
Beginning March 31, 2009, representatives of Portland General Electric Company will meet with various members of the financial and investment community, at which meetings the material contained in the exhibit attached hereto as Exhibit 99.1 will be presented.
| Item 9.01 | Financial Statements and Exhibits. |
| (d) | Exhibits |
| Exhibit |
Description | |
| 99.1 | Portland General Electric Company investor presentation dated March 31, 2009 and April 1 & 2, 2009. | |
2
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| PORTLAND GENERAL ELECTRIC COMPANY (Registrant) | ||||||||
| Date: March 31, 2009 |
By: | /s/ Maria M. Pope | ||||||
| Maria M. Pope Senior Vice President, Chief Financial Officer and Treasurer | ||||||||
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Exhibit 99.1
Investor Roadshow
March 31, 2009 April 1 & 2, 2009
Copyright © 2008 Portland General Electric. All Rights Reserved.
Cautionary Statement
Information Current as of February 25, 2009
Except as expressly noted, the information in this presentation is current as of February 25, 2009 — the date on which PGE filed its Annual Report on Form 10-K for the year ended December 31, 2008 — and should not be relied upon as being current as of any subsequent date. PGE undertakes no duty to update the presentation, except as may be required by law.
Forward-Looking Statements
This presentation contains statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions identify forward-looking statements. The forward-looking statements in this presentation include, but are not limited to, statements concerning long-term growth of the Oregon economy and PGE’s retail load; statements concerning the expected decline in PGE’s retail load in 2009; statements concerning changes in PGE’s energy portfolio; statements concerning estimated future capital expenditures; statements concerning future growth in rate base; statements concerning the completion dates, costs and rate treatment of the smart metering project and Phases II and III of the Biglow Canyon Wind Farm project; statements concerning the estimated cost savings from deployment of smart metering; statements concerning future financing activities; statements concerning the anticipated roll-off of margin deposits; statements concerning the recovery of costs through future rate increases; statements concerning future dividend payouts; statements concerning the outcome of various legal and regulatory proceedings; statements concerning the outcome of the renewables request for proposals; and statements concerning the future effect of Senate Bill 408.
Although PGE believes that the expectations reflected in any forward-looking statements are based on reasonable assumptions, PGE can give no assurance that its expectations will be attained. Factors that could cause actual results to differ materially from those contemplated include, among others, capital market conditions, events related to governmental policies; the outcome of legal and regulatory proceedings; the costs of compliance with environmental laws and regulations, including those that govern emissions from thermal power plants; changes in weather, hydroelectric, and energy market conditions; wholesale energy prices, which could affect the availability and cost of fuel or purchased power; rate treatment of capital projects; operational factors affecting PGE’s power generation facilities; growth and demographic patterns in PGE’s service territory; general political, economic, and financial market conditions; and other factors that might be described from time to time in PGE’s filings with the Securities and Exchange Commission. Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement.
| 2 |
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Portland General Investment Highlights
“Pure-play” electric utility – Vertically integrated, regulated electric utility
– Attractive service territory and constructive regulatory dialogue
– 10.0% ROE on 50% equity capitalization
Operational excellence – Diversified, high-performing generation portfolio
– Well-managed power supply operations
– High quality, well-maintained T&D system
– Highest in Western region in overall business customer satisfaction (1)
Low-risk growth plan – Identified regulated capital investments of approximately
$1.1 billion (2) (2009-2013) drive rate base growth
– Wind investments to facilitate compliance with Oregon
Renewable Energy Standard
– Track record of completing projects on time and within budget
Prudent financial strategy – Investment grade ratings of BBB+ / Baa2 (unsecured)
– Target capital structure: 50% debt, 50% equity
– Focus on maintaining a strong balance sheet and adequate levels of liquidity
Stability:
Dividend Yield
Attractive total return proposition
Growth:
EPS growth
| 3 |
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(1) Portland General Electric ranks highest in the Western region in overall business customer satisfaction according to the J.D. Power and Associates 2009 Electric Utility Business Customer Satisfaction Study SM
| (2) |
|
Represents total capital expenditures less depreciation and amortization. |
Portland General Strategic Direction
Mission: To be a company our customers and communities can depend upon to provide electric service in a safe, responsible and reliable manner, with excellent customer service, at a reasonable price.
Operational Excellence
Customer satisfaction Operational efficiency Power supply, system reliability and service quality Engage and develop our people
Business Growth
Strategic system investments Encourage economic vitality Capitalize on emerging technologies
Corporate Responsibility
Listen and lead in public policy Trusted convener for customers and stakeholders Continued commitment to the Oregon community
Deliver Value to Customers and Shareholders
| 4 |
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Attractive Regulated Business Profile
Straightforward electric utility model
Vertically integrated
Single-state jurisdiction
Virtually 100% regulated business providing stable earnings and cash flows
No holding company structure
Attractive, compact service territory with 810,197 retail customer accounts(1)
Includes 52 incorporated cities including Portland and Salem
• Engaged in generation, purchase, transmission, distribution and retail sale of electricity
• Diversified and growing customer base
• Constructive regulatory relationship with the Oregon Pubic Utility Commission (OPUC)
Net Utility Plant
Other
CWIP $251 million
$281 million Generation
$1,007 million
Transmission
$196 million
Distribution
$1,064 million
Net Utility Plant – $2,799 million(2)
| 5 |
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| (1) |
|
As of December 31, 2008. (2) Source: 2008 FERC Form 1. |
Attractive Service Territory
Weather Adjusted Load Growth (1)
(thousands of MWH)
20,000 19,000 18,000 17,000
| 1 |
|
. 4 % a nnua l g r o w t h |
2003 2004 2005 2006 2007 2008
2008 Retail Revenues by Customer Group
Industrial 10%
Commercial 40%
Residential 50%
Total = $1.5 Billion
| (1) |
|
Adjusted for weather and certain industrial customers |
Commentary
PGE has achieved consistent customer growth in its service area
Compounded annual customer growth of 1.5% and load(1) growth of 1.4% since the end of 2003
Growth in Oregon’s economy is expected to require further investment by PGE to meet increased energy demand
Population growth in Oregon has exceeded United States average: 1.2% vs. 1.0% from 2007-2008
Population growth of counties in PGE’s service area has exceeded rest of state
No single customer accounts for more than 2% of total retail revenues
Load growth for 2009 was expected to be flat relative to 2008. However, PGE is continuing to review its load forecast and currently expects loads to decline by 0.5% to 1.0% relative to 2008.
Decline in loads from previous forecast driven primarily by reduction in industrial loads
6
Constructive Regulatory Environment
Oregon Public Utility Commission
Governor-appointed Commission with staggered four-year terms (Lee Beyer 3/2012, Ray Baum 8/2011, John Savage 3/2009)
Forward Test Year
Net Variable Power Cost Recovery
Annual Update Tariff (1)
Power Cost Adjustment Mechanism (1)
Cost of Capital and Return on Equity
10.0% Allowed Return on Equity
50% Debt, 50% Equity
8.28% Weighted Average Cost of Capital
Decoupling
Intended to allow recovery of fixed revenue requirement as a result of lower sales of electricity from customers’ energy efficiency and conservation efforts
Integrated Resource Plan
Acknowledgement standard
2009 IRP—longer-term analysis to address resource decisions through 2020
Renewable Energy Standard
Standard requires that 25 percent of PGE’s electricity come from renewable sources by 2025
Renewable Adjustment Clause (RAC)—PGE can recover costs of renewable resources through a separate filing
| 7 |
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| (1) |
|
See Appendix |
Operational Excellence
Operational Efficiency
• Ongoing investments to improve quality of service, maintain costs and generate adequate returns
Smart Meter Program
Capex: $130-$135 million
$18 million in annual savings projected by 2011
Customer Satisfaction
Highest customer satisfaction with business electric service in Western
U.S. according to J.D. Power and
Associates 2009 Electric Utility Business Customer Satisfaction Study SM
Residential customer satisfaction ratings among the highest in the industry
Highly reliable system with 92 percent plant availability in 2008
On-going infrastructure investments to ensure high level of reliability, safety and customer satisfaction
Invested more than $775 million in the last 5 years in transmission, distribution, and existing generation
Well Maintained, High-Quality System
| 8 |
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Operational Excellence
Manage power supply operations to:
• Capitalize on PGE’s assets and position in the marketplace
• Meet load in most economic fashion to lower cost to customers
• Manage and monitor risks with appropriate systems and processes
to assure strategy is implemented prudently
Communication is one of the keys to our strategy
9
Operational Excellence
Generation Capacity (at 12/31/08)
Physical % of Total
Capacity Capacity
Hydro
Deschutes River Projects 298 MW 6.7%
Clackamas/Willamette
River Projects 191 4.3
Hydro Contracts 695 15.6
1,184 26.6
Natural Gas/Oil
Beaver Units 1-8 529 MW 11.9%
Coyote Springs 233 5.2
Port Westward 413 9.3
1,175 26.4
Coal
Boardman 374 MW 8.4%
Colstrip 296 6.6
670 15.0
Wind(2)
Wind Contracts 35 MW 0.1%
Biglow Canyon Phase I 46 1.0
81 1.8
Net Purchased Power
Short-/Long-term 1,345 MW 30.2%
Total 4,455 MW 100.0%
Power Sources as % of Retail Load
2008 Actual
Purchased Power
Gas/Oil
20%
27%
24%
29%
Coal
Hydro/Wind(1)
2007 Actual
Purchased Power
Coal
25% 27%
Gas/Oil
19% 29%
Hydro/Wind(1)
(1) Includes PGE owned and purchased hydro resources and PGE owned and purchased wind resources. (2) Physical capacity for wind resources provided in average megawatts
10
Smart Grid
Smart Meters
Provides two-way communications with residential and commercial customers
Vendor: Sensus Metering Systems
Technology: FlexNet radio frequency technology
Deployment: 850,000 residential and commercial customers
Estimated cost: $130 million—$135 million
Estimated completion: 2010
OPUC approved limited term tariff: June 1, 2008 through December 31, 2010. After 2010 the projects costs, net of savings, would be permanently incorporated into rates in a future rate case
Distribution System
Pursuing direct load control programs
Optimizing distribution system through advanced technology
11
Business Growth
Load Growth
PGE’s long-term retail load is expected to grow consistently while selected long-term power purchase contracts expire, driving the need for additional generation capacity
Load Resource Balance Annual Average Energy(1)(2)
Retail Load & Resource Balance Peak Capacity(1)(3)
| (1) |
|
Data as of February 2009. |
(2) Load forecast does not include 30 MWa of non-cost of service loads. (3) Load forecast does not include 31 MW of non-cost of service loads.
Note: Assumes 1.9% load growth through 2030 and energy supply based on plant capabilities under normal hydro and operating conditions.
12
Business Growth
Growth is driven by investment in renewable resources, technology and environmental projects
Projects (in millions)1 2008 2009 2010 2011 2012 2013
Biglow Canyon Wind Farm: Phase II $75 $230 — —— -
Biglow Canyon Wind Farm: Phase III $22 $176 $201 —— -
Smart metering $10 $66 $53 —— -
Boardman emissions controls2 $1 $2 $25 $255—$295
Hydro licensing and construction $54 $24 $15 $50—$70
Total Projects $162 $498 $294 —— -
Ongoing capital expenditures3 $210 $224 $232 $210 —$230 $265—$285 $240—$260
Total Projects and Ongoing $372 $722 $526
Other Potential Investments:
• RFP issued in 2008 for up to 218 MWa of renewable resources
– Purchase power and ownership options being considered
– Final short list identified with agreements expected to be completed in 2009
• Southern Crossing Transmission project
– 225 mile, 500KV (2013-2015)
– Designed to meet growing demand, provide improved system reliability and reduce transmission payments
• Additional energy and capacity resources as identified in the Company’s Integrated Resource Plan to be filed by the end of 2009
(1) Current as of December 31, 2008 (refer to cautionary statement). Does not include allowance for funds used during construction (AFDC). Forecasted expenditures are preliminary and subject to change.
(2) Represents 80% of the DEQ proposal. Total expenditures under the DEQ proposal are expected to be $575 million—$636 million (100% of estimated cost in nominal dollars and excluding AFDC).
| (3) |
|
Includes upgrades to transmission, distribution and existing generation, as well as new customer connections. |
13
Business Growth
Generation expansion successfully completed on time and within budget
Port Westward (completed)
• 413 MW gas-fired plant utilizing Mitsubishi G-class turbine
• $280 million, including AFDC
• 6,826 Btu/kWh heat rate (without duct-firing)
• Placed into service June 11, 2007
Biglow Canyon Wind Farm
• Columbia Gorge, eastern Oregon
• 450 MW total installed capacity
Phase I (on time and on budget)
– $255 million, including AFDC
– 125 MW nameplate capacity
– Online and in prices effective January 1,
2008
Phases II & III
Phase II Phase III
Nameplate capacity 150MW, 65 turbines 175MW, 76 turbines
Cost (w/AFDC) $326 million (1) $433 million (1)
Online date December 2009 December 2010
Contractor Siemens Siemens
| (1) |
|
Based on December 31, 2008 10-K . |
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Business Growth
Rate Base (Average)
($ millions) 2,600 2,500 2,400 2,300 2,200 2,100 2,000 1,900 1,800 1,700 1,600
| 5 |
|
. 0 % a nnua l g r o w t h |
$2,009
$1,766
$2,237
$2,484 (1)
2002 2007 2008 2009E
Capital Expenditures
($ millions)
800 700 600 500 400 300 200 100 0
2007 2008 2009E 2010E
$455 $372
$722(2)
| (2) |
|
$526
Commentary
Attractive, near-term regulated growth opportunities through capital investment in core utility assets
Approximately $1.1 billion of identified capital projects (2009 – 2013) net of depreciation and amortization
Reduced short-term capital expenditure for 2009 by $38 million
Depreciation and amortization of $205 million—$255 million annually (2009 – 2013)
New capital investments funded through cash from operations and issuances of debt and equity with a targeted capital structure of 50/50
(1) Includes the General Rate Case average rate base of $2.278 billion plus Biglow Canyon Phase II, the Selective Water Withdrawal project, and the Smart Metering project. Excludes potential benefits from the American Recovery and Reinvestment Act of 2009. (2) Forecasted capital expenditures are preliminary and subject to change.
15
Prudent Financial Strategy
Target Capital Structure 50% Debt, 50% Equity
Debt Issuance
• PGE anticipates issuing approximately $300 million of new long-term debt in 2009
• $130 million of First Mortgage Bonds (FMB) issued in January 2009 consisting of:
– $67 million @ 6.80%, maturing in 2016
– $63 million @ 6.50%, maturing in 2014
• $150—$170 million of additional FMBs expected to be issued in 2009 (excluding remarketing of $142 million in tax-exempt bonds)
• On May 1, 2009, $142 million of tax-exempt bonds have a mandatory tender (backed by FMB)
• In lieu of remarketing the tax-exempt bonds the Company may hold the bonds and pay-off investors by issuing $140 - $150 million of FMBs
• After considering the issuance of $130 million of FMBs in January 2009, FMB capacity under the most restrictive issuance test as of December 31, 2008 was approximately $600 million. FMB capacity at year end 2009 is expected to be in the $650—$700 million range
• PGE anticipates issuing approximately $375 million of long-term debt in 2010
Equity Issuance
• On March 11, 2009 PGE completed a public offering of approximately 12.5 million shares of common stock at $14.10 per share, including a 1.6 million share overallotment option fully exercised by the underwriters
• Gross proceeds before deducting underwriting discounts, commissions and estimated offering expenses: $175.9 million
• Additional equity issuance currently not expected until after 2010. Timing of additional equity needs could be impacted by the outcome of the request for proposal for up to 218 MWa of renewables
16
Prudent Financial Strategy
Debt/Capitalization
Manageable Near-term Debt Maturities
($ millions)
60% 55% 50% 45% 40% 35% 30%
| (1) |
|
2005 2006 2007 2008 2009E
2009 2010 2011 2012 2013
Credit Ratings
Senior Secured Senior Unsecured Outlook
S&P A BBB+ Negative
Moody’s Baa1 Baa2 Positive
Dividend Growth
Quarterly dividend Actual Payout ratio Target payout ratio
Target payout ratio: 60%
2008 payout ratio: 56%(2) 2007 payout ratio: 39%
0.245 0.245 0.245
+4.3%
0.235 0.235 0.235 0.235
+4.4%
0.225 0.225 0.225 0.225
Jul- Oct- Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-
06 06 07 07 07 07 08 08 08 08 09
| (1) |
|
Includes March 2009 equity issuance |
| (2) |
|
Based on 2008 EPS of $1.39 adjusted for Trojan Refund Order Provision of $0.32 resulting in adjusted EPS of $1.71 |
17
Liquidity (as of 3/20/09)
Liquidity ($ millions)
500 400 300 200 100 0
$495 $218 $25
Revolving Credit Facilities Revolver Usage Cash
Commentary
$370 million revolving credit facility
$360 million matures in July 2013
$10 million matures in July 2012
$125 million 364-day revolving credit facility matures in December 2009
Revolver usage as of March 20, 2009 was:
$218 million in letters of credit
Margin deposits posted by PGE as of March 20, 2009 were $429 million
Margin deposits create a cash flow timing difference but have minimal impact on earnings
Margin roll-off(1)
Approximately 50% in 2009
Approximately 40% in 2010
| (1) |
|
Assumes market prices remain unchanged and minimal new incremental transactions |
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Portland General Investment Highlights
“Pure-play” electric utility
Operational excellence
Low-risk growth plan
Prudent financial strategy
Stability:
Dividend Yield
Attractive total return proposition
Growth:
EPS Growth
19
Investor Relations Contact Information
William J. Valach
Director, Investor Relations 503-464-7395 William.Valach@pgn.com
Portland General Electric Company 121 S.W. Salmon Street Suite 1WTC0403 Portland, OR 97204
www.PortlandGeneral.com
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Appendix
Table of Contents
• Earnings Summary p.22
• General Rate Case p.23
• Power Cost Adjustment Mechanism (PCAM) p.24-25
• Decoupling Mechanism p.26
• Senate Bill 408 p.27
• Other Regulatory and Legal Considerations p.28
• Boardman BART p.29
• American Recovery & Reinvestment Act of 2009 p.30
21
Earnings Summary
Net Income
($ millions)
$200 $150 $100 $50 $0
2006 2007 2008 2009E
$145 $131-$138
$87 $71
Earnings per Share
$2.50 $2.00 $1.50 $1.00 $0.50 $0.00
$2.33
$1.80—$1.90 $1.14 $1.39
2006 2007 2008 2009E
Key Items ($ earnings per diluted share)
2006
Boardman outage (-$0.51) and deferral (+$0.06)
Mark-to-market accounting (+$0.05)
Senate Bill 408 (-$0.41)
2007
Boardman deferral (+$0.26)
California settlement (+$0.06)
Non-qualified benefit plan assets (+.05)
Senate Bill 408 (+$0.18)
2008
Trojan Refund Order Provision (-$0.32)
Non-qualified benefit plan assets (-$0.19)
Beaver oil sale (+$0.10)
Senate Bill 408 (-$0.10)
2009
As of February 25, 2009 earnings guidance was reaffirmed at $1.80 to $1.90 per diluted share
22
2009 General Rate Case Update
Outcome of Oregon Public Utility Commission (OPUC) final order regarding PGE’s rate case:
Regulatory Structure
• Allowed ROE: 10.0% (1)
• Equity capitalization: 50%
• Debt capitalization: 50%
• Return on rate base: 8.28%
• Methodology for modeling net variable power cost (NVPC)
Rate Base and Revenue
• Average rate base: $2.278 billion(2)
• Rate increase: $121 million
– % increase: 7.3%(3)
– NVPC: $95.4 million
– O&M, A&G and other: $25.6 million
Commentary
The increase became effective January 1, 2009
The OPUC accepted PGE’s recommendation for a decoupling mechanism for a period of two-years. On January 30, 2009 PGE filed with the OPUC for deferred accounting of revenues associated with the decoupling mechanism. On March 24, 2009 the Citizen’s Utility Board (CUB) filed with the OPUC seeking reconsideration of decoupling decision
| (1) |
|
Reduction from 10.1% to 10.0% as a condition of decoupling. |
(2) Excludes smart metering, selective water withdrawal and Phases II & III of the Biglow Canyon Wind Farm. Average rate base including smart metering, selective water withdrawal and Phase II of Biglow Canyon Wind Farm is $2.484 billion.
(3) Certain customer credits from the 2007 Power Cost Adjustment Mechanism effectively reduces the customer increase from 7.3% to 5.6%.
23
Recovery of Power Costs
Annual Power Cost Update Tariff
• Annual reset of rates based on forecast of net variable power costs (NVPC) for the coming year. Following OPUC approval, new prices go into effect on or around January 1 of the following year.
Power Cost Adjustment Mechanism (PCAM)
Power Cost Sharing
Customer Surcharge
90/10 Sharing
150 Bps $28 million(1) of ROE
Baseline
NVPC (1) 75 Bps
($14) million of ROE
90/10 Sharing
Customer Refund
Return on Equity
Earnings Test
Customer Surcharge
9.1%
100 Bps
10.1%
100 Bps
11.1%
Customer Refund
PGE absorbs 100% of the costs/benefits within the deadband, and amounts above or below the deadband are shared 90% with customers and 10% with PGE.
An annual earnings test is applied as part of the PCAM.
Customer surcharge occurs to the extent it results in PGE’s actual ROE being no greater than 9.1%
Customer refund occurs to the extent it results in PGE’s actual ROE being no less than 11.1%
| (1) |
|
Deadband for 2008. |
| 24 |
|
Recovery of Power Costs
Power Cost Adjustment Mechanism (PCAM) Example—2008
Power Cost Sharing
150 Bps $28 million(1) of ROE
Baseline
NVPC (1) 75 Bps
($14) million of ROE
Actual NVPC $31 million below baseline NVPC
2008 net variable power costs (NVPC) were $31 million less than the baseline NVPC
PGE retained the portion of lower power costs that are inside the deadband, in 2008 this amount was $14 million
Earnings Test
9.1%
Equity 100 Bps
on 10.1%
Regulated ROE below 11.1% 100 Bps
Return 11.1%
PGE’s regulated ROE for 2008 was below the 11.1% threshold for a refund.
If regulated ROE is 11.1% or more customers would have received a refund of approximately $15 million(2) but since regulated ROE was below 11.1% no refund was made.
| (1) |
|
Deadband for 2008. |
| (2) |
|
Calculated as follows: $31mm—$14mm = $17mm. $17mm x 90% = $15mm. |
25
Decoupling Mechanism
The decoupling mechanism is intended to allow recovery of reduced earnings resulting from a reduction in sales of electricity resulting from customers’ energy efficiency and conservation efforts
A condition of the decoupling mechanism is a reduction in the Company’s allowed ROE from 10.1% to 10.0% which reflects the OPUC’s view of a reduction in Company risk. The ROE refund is estimated at approximately $1.9 million annually
Implemented under a new two-year tariff that includes a Sales Normalization Adjustment (SNA) for residential and small non-residential customers and a Nonresidential Lost Revenue Recovery (LRR), for large non-residential customers
The SNA is based on the difference between actual, weather-adjusted usage per customer and that projected in PGE’s recent general rate case
The LRR is based on the difference between actual energy-efficiency savings (as reported by the ETO) and those incorporated in the applicable load forecast
On January 31, 2009, PGE filed an application with the OPUC to defer, for later rate- making treatment, potential revenues associated with the new decoupling mechanism as well as revenues associated with an ROE refund
Mechanism effective February 1, 2009
On March 24, 2009 CUB filed with the OPUC seeking reconsideration of decoupling decision
26
Oregon Senate Bill 408
Beginning January 1, 2006, SB 408 requires the OPUC to track estimated income taxes collected by Oregon utilities in rates and compare this amount to adjusted taxes paid to taxing authorities by the utility or corporate consolidated group. The OPUC may establish deferral accounts to capture the difference
SB 408 requires an annual rate adjustment if difference between taxes authorized to be collected by the utility and taxes paid by the utility to taxing authorities exceed $100,000
Report for prior calendar year is filed in October with the refund or collection beginning in June of the following year. For example:
The 2008 report of taxes paid is filed in October 2009. New tariff goes into effect June 2010, if necessary
Primary issue for PGE is the so called “double whammy” effect, due to the OPUC adopting a fixed reference point for margins and effective tax rates. The double whammy can result in unusual outcomes and increased financial volatility in certain situations. The OPUC stated in the final order that it will be responsive to concerns related to the consequences of the double whammy problem, and may address those concerns in other regulatory proceedings
Historical/expected outcomes:
2006: Customer refund of approximately $37.2 million plus accrued interest
2007: Customer collection of $14.7 million plus accrued interest
2008: Customer refund of approximately $10 million plus accrued interest
27
Other Regulatory and Legal Considerations
Selective Water Withdrawal Project
• Pelton/Round Butte project to restore fish passage on the upper Deschutes River
• Capital cost (PGE share) approximately $80 million (including AFDC)
• Project completion expected in the second quarter 2009
• OPUC docket: UE 204
Boardman Coal Plant Deferral
• Request with the OPUC to amortize a $26.4 million deferral of replacement power costs, plus accrued interest ($7.8 million as of December 31, 2008) associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006
• Request subject to prudency review and regulated earnings test
• OPUC docket: UE 196
Trojan Nuclear Plant: Recovery of Return on Investment
• OPUC Proceedings
• Class Action Proceedings
28
Boardman BART Update
Best Available Retrofit Technology (BART) for compliance with EPA Regional Haze Rule
In December 2008, the Department of Environmental Quality (DEQ) issued a proposed plan that would require the installation of controls in three phases:
Phase 1: Installation of low NOx burners, completion by 2011 Phase 2: Installation of semi-dry scrubber and bag house to address mercury and sulfur dioxide removal, completion by 2014 Phase 3: Installation of Selective Catalytic Reduction for additional NOx controls, completion by 2017 DEQ proposes that Phases 1 and 2 would meet federal BART requirements. Phase 3 is recommended by the DEQ to make reasonable progress towards haze emission reduction goals.
PGE cost estimate for Phases 1, 2 and 3 for the DEQ plan: $575 to $636 million (1)
PGE proposed an alternative in their comments that would allow for decision points along the DEQ timeline to provide flexibility to make the most cost-effective decision on future controls at those points.
The comment and public input period for the DEQ proposal has closed
• Schedule:
– Oregon EQC decision on BART June 2009
– EPA approval Early 2010
| (1) |
|
100% of estimated cost in nominal dollars and excludes AFDC. |
29
American Recovery & Reinvestment Act of 2009
PGE is evaluating the impact and certain benefits that may be available under the American Recovery and Reinvestment Act of 2009 (the Act)
The Act provides a number of enhanced tax benefits, many of which are highly favorable to renewable energy projects such as PGE’s Biglow Canyon windfarm:
For windfarms the Production Tax Credit (PTC) was extended from 2009 through 2012
In lieu of the PTC, the company may elect either:
Investment Tax Credit (ITC) – upfront 30% tax credit
Treasury Department Grants (1) – Cash payment in lieu of claiming PTC or ITC
Based on PGE’s preliminary assessment of current provisions of the Act, the Company believes that it may be entitled to qualify for the Treasury Department grant option in amounts ranging from:
$60 million to $90 million for Biglow Canyon Phase II in 2009
$80 million to $110 million for Biglow Canyon Phase III in 2010
The availability of any such grants under the Act and the Company’s final determination of whether to seek such grants or other benefits under the Act are subject to various other factors.
Accordingly, there is no assurance that the Company will either seek or receive any grants or other benefits under the Act.
(1) For qualifying renewable energy facilities placed in service in either 2009 or 2010, or for qualifying renewable energy facilities on which construction commenced during 2009 or 2010 and that are placed in service after 2010 but prior to 2013.
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