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POR > SEC Filings for POR > Form 10-Q on 8-Nov-2012All Recent SEC Filings




Quarterly Report

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future operations, business prospects, expected changes in future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," "should," or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, but not limited to, management's examination of historical operating trends and data contained in records and other data available from third parties, but there can be no assurance that PGE's expectations, beliefs or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

governmental policies and regulatory audits, investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities,

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transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;

economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;

the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

unseasonable or extreme weather and other natural phenomena, which can affect customers' demand for power and could significantly affect PGE's ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company's costs to maintain its generating facilities and transmission and distribution systems;

operational factors affecting PGE's power generation facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, which may cause the Company to incur repair costs, as well as increased power costs for replacement power;

the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, which could result in the Company's inability to recover project costs;

volatility in wholesale power and natural gas prices, which could require the Company to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to existing power and natural gas purchase agreements;

capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper, as well as changes in PGE's credit ratings, which could have an impact on the Company's cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayments of maturing debt;

future laws, regulations, and proceedings that could increase the Company's costs or affect the operations of the Company's thermal generating plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;

changes in wholesale prices for fuels, including natural gas, coal, and oil, and the impact of such changes on the Company's power costs, and changes in the availability and price of wholesale power in the western United States;

changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE's service territory;

the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;

declines in the fair value of equity securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;

changes in, and compliance with, environmental and endangered species laws and policies;

the effects of climate change, including changes in the environment, which may affect energy costs or consumption, increase the Company's costs, or adversely affect its operations;

new federal, state, and local laws that could have adverse effects on operating results;

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cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company's generation and transmission facilities or information technology systems, or result in the release of confidential customer and proprietary information;

employee workforce factors, including a significant number of employees approaching retirement, potential strikes, work stoppages, and transitions in senior management;

general political, economic, and financial market conditions;

natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;

financial or regulatory accounting principles or policies imposed by governing bodies; and

acts of war or terrorism.

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 to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.


Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company's condensed consolidated financial statements contained in this report, as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2011, and other periodic and current reports filed with the SEC.

Operating Activities - PGE is a vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity, as well as the wholesale purchase and sale of electricity and natural gas. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The impact of seasonal weather conditions on demand for electricity can cause the Company's revenues and income from operations to fluctuate from period to period. PGE is a winter-peaking utility that typically experiences its highest retail energy sales during the winter heating season, although a slightly lower peak occurs in the summer that generally results from air conditioning demand. Price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while the availability and price of purchased power and fuel can affect income from operations.

Customers and Demand - Retail energy deliveries for the nine months ended September 30, 2012 decreased approximately one-half of one percent from the comparable period of 2011 largely as a result of the impact of relatively warmer weather during the heating season early in 2012 reducing residential customer demand, and the loss of demand from one large paper customer in early 2011. The decline was partially offset by an increase in the average number of total retail customers served.

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The following table indicates the average number of retail customers, including those direct access customers who chose to purchase their energy from an Electricity Service Supplier (ESS), and energy deliveries, by customer class, for the periods indicated:

                                        Nine Months Ended September 30,
                                      2012                            2011
                           Average                          Average                             % Increase
                          Number of      Retail Energy     Number of     Retail Energy     /(Decrease)in Energy
                          Customers      Deliveries *      Customers     Deliveries *           Deliveries
Residential                722,884              5,506       719,809             5,604               (1.7 )%
Commercial                 103,798              5,566       102,911             5,560                0.1
Industrial                     261              3,180           255             3,156                0.8
Total                      826,943             14,252       822,975            14,320               (0.5 )

* In thousands of MWh.

On a weather adjusted basis, total retail energy deliveries for the nine months ended September 30, 2012 increased approximately one-half of one percent compared to the same period of 2011. PGE expects the increase in total retail energy deliveries on a weather adjusted basis for the year ending December 31, 2012 to approximate the increase for the nine months ended September 30, 2012, after allowing for energy efficiency and conservation efforts.

Power Operations - To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and wholesale market transactions. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, PGE makes economic dispatch decisions continuously in an effort to obtain reasonably-priced power for its retail customers. In addition, PGE's thermal generating plants require varying levels of annual maintenance, during which the respective plant is unavailable to provide power. As a result, the amount of power generated and purchased in the wholesale market to meet the Company's retail load requirement can vary from period to period.

During the second quarters of 2012 and 2011, such annual maintenance was performed, with more extensive, planned service maintenance completed in 2011 compared to 2012. The work performed during 2011 included planned emissions control retrofits at Boardman and the replacement of the cooling tower structure and upgrading of the gas turbine and exhaust system components at Coyote Springs. Availability of the plants PGE operates approximated 93% and 92%, for the nine months ended September 30, 2012 and 2011, respectively, with the availability of Colstrip, which PGE does not operate, approximating 92% and 80%, for the same periods, respectively.

During the nine months ended September 30, 2012, the Company's generating plants provided approximately 47% of its retail load requirement, compared with 44% in the nine months ended September 30, 2011. The increase in the relative volume of power generated to meet the Company's retail load requirement was primarily due to the economic displacement of a greater amount of thermal generation by lower cost purchased power during 2011.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 30% in the nine months ended September 30, 2012 compared with the same period of 2011. These resources provided approximately 20% of the Company's retail load requirement for the nine months ended September 30, 2012, compared with 28% for the same period of 2011. Through September, energy received from these sources exceeded projections included in the Company's Annual Power Cost Update Tariff (AUT) by approximately 12% during 2012, compared with 17% during the comparable period of 2011. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year and are based, in part, on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy from hydro resources is expected to be

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approximately 9% above projections included in the AUT for 2012.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon) is projected annually in the AUT and is based on wind studies completed in connection with the permitting of the wind farm. Any excess in wind generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy received from Biglow Canyon fell short of that projected in PGE's AUT by 17% and 11%, in the nine months ended September 30, 2012 and 2011, respectively, and provided approximately 7% of the Company's retail load requirement for the nine months ended September 30, 2012 and 2011.

Pursuant to the Company's power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year's forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC for the year. To the extent actual NVPC is above or below the deadband, the PCAM provides for 90% of the variance to be collected from or refunded to customers, respectively, subject to a regulated earnings test. Pursuant to the regulated earnings test, a refund will occur only to the extent that it results in PGE's actual regulated return on equity (ROE) for that year being no less than 1% above the Company's latest authorized ROE of 10%, while a collection will occur only to the extent that it results in PGE's actual regulated ROE for that year being no greater than 1% below the Company's authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company's statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For 2012 and 2011, the deadband range is from $15 million below to $30 million above baseline NVPC.

For the nine months ended September 30, 2012, actual NVPC was approximately $14 million below baseline NVPC due to strong power supply operations and above average hydro generation, partially offset by lower than expected wind generation. Based on forecast data, NVPC for the year ending December 31, 2012 is currently estimated to be below the baseline NVPC, but within the deadband range; accordingly, no estimated refund to customers is expected for 2012.

For the nine months ended September 30, 2011, actual NVPC was approximately $36 million below baseline NVPC, which is $21 million below the lower deadband threshold, with PGE recording an estimated refund to customers in the amount of $17 million during the period. Upon application of the regulated earnings test, the estimated refund to customers was reduced to $10 million as of December 31, 2011.

Capital Requirements and Financing - PGE's capital requirements for 2012 are related primarily to ongoing expenditures for the upgrade, replacement, and expansion of transmission, distribution, and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing and construction. Capital expenditures are expected to be approximately $328 million in 2012, of which $218 million was incurred through September 30, 2012. For further information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

For 2012, the Company expects to meet capital requirements with cash from ongoing operations, with no issuances of long-term debt or equity. In subsequent years, the Company expects to fund its capital requirements with a combination of cash from operations and funds from the capital markets, depending on the outcome of the Integrated Resource Plan (IRP) process outlined below, PGE's liquidity needs, and market conditions. The Company also expects that the borrowing capacity under its credit facilities will continue to be available to manage working capital requirements for the foreseeable future. For further information, see the Debt and Equity Financings section of Liquidity and Capital Resources in this Item 2.

PGE's 2009 IRP, acknowledged by the OPUC in November 2010 and updated in November 2011, includes the Company's strategy for acquiring new resources over the next several years and a 20-year strategy outlining long-term expectations for resource needs and portfolio management. To meet projected energy requirements, the IRP includes energy efficiency measures, additional renewable resources, new transmission capability, new generation, and improvements to existing generating plants. The Company expects to file with the OPUC another update to the

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IRP by the end of November 2012.

In June 2012, in accordance with the IRP and pursuant to the OPUC's competitive bidding guidelines, the Company issued a request for proposals (RFP) for additional resources seeking a combination of capacity and energy resources. The RFP seeks approximately:

300 to 500 MW of base load energy resources;

200 MW of year-round flexible and peaking resources;

200 MW of bi-seasonal (winter and summer) peaking supply; and

150 MW of winter-only peaking supply.

This RFP closed to proposals in August 2012, with PGE receiving proposals consisting of a mix of projects to be sold to the Company pursuant to asset purchase agreements and projects that would sell power to the Company under long-term power purchase agreements. PGE, with the oversight of an independent evaluator, is in the process of evaluating the bids, which include Company benchmark proposals. A final short list of projects is expected by the end of 2012. Negotiations with final short listed bidders are expected to start in late 2012 or early 2013. The flexible and peaking resources are expected to be available in the 2013 to 2015 time frame and the base load energy resources expected to be available in the 2014 to 2017 time frame.

A second RFP, which was issued in October 2012, is seeking approximately 100 MWa of renewable resources in order to help meet PGE's 2015 requirements under Oregon's Renewable Portfolio Standard. Sources proposed must meet a minimum size of at least 10 MW and can represent a variety of technologies including wind, geothermal, biomass, biogas, solar, and hydroelectric power. PGE may acquire a single resource or a mix of resources to achieve the total desired renewable energy target. The Company submitted a benchmark proposal at the end of October and all other proposals are due by November 13, 2012. PGE expects to identify an initial short list of projects by January 2013, with a final short list expected in early February 2013. The renewable resources are anticipated to be in service in the 2013 to 2017 time frame.

The IRP includes a proposal for an approximately 215-mile, 500 kV transmission line referred to as the Cascade Crossing Transmission Project, or Cascade Crossing, that would help meet future electricity demand and improve regional grid reliability. The project would transmit power from new and existing energy resources in northeastern Oregon to the Company's service territory. PGE continues to work with other stakeholders in the region in planning the project and is actively engaged in the federal, state, and tribal permitting processes. Subject to obtaining all necessary approvals, the in-service date is not expected before 2017.

For additional information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

Legal, Regulatory, and Environmental Matters - PGE is a party to certain proceedings, the ultimate outcome of which may have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, the following matters:

Challenges to recovery of the Company's investment in its closed Trojan plant;

Claims for refunds related to wholesale energy sales during 2000 - 2001 in the Pacific Northwest; and

An investigation of environmental matters regarding Portland Harbor.

For additional information regarding the above and other matters, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

The following discussion highlights certain regulatory items that have impacted the Company's revenues, results of operations, or cash flows for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 or affected retail customer prices, as authorized by the OPUC. In some cases, the Company

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deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Boardman Operating Life Adjustment - In PGE's 2011 General Rate Case, the OPUC approved a tariff that provides a mechanism for future consideration of customer price changes related to the recovery of the Company's remaining investment in the Boardman generating plant over a shortened operating life. Pursuant to the tariff, the OPUC approved recovery of increased depreciation expense reflecting a change in the retirement date of Boardman from 2040 to 2020, with new prices effective July 1, 2011, which provided incremental revenues for the last six months of 2011 of $7 million. In 2012, the annual revenue requirement for the full year is expected to be $13 million.

Power Costs - Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. In November 2011, the OPUC issued an order on the 2012 AUT resulting in an estimated 1% decrease in customer prices as a result of expected lower power costs. The new prices became effective January 1, 2012 and are expected to result in a decline of approximately $22 million in annual revenues compared to 2011.

The Company submitted an updated forecast of 2013 power costs to the OPUC in October 2012. Based on the latest estimate, which will be updated and finalized in November 2012, power costs for 2013 are expected to be lower than 2012, with a corresponding decrease in customer prices between 1% and 2% becoming effective January 1, 2013. The resulting annual revenue requirement is expected to decrease by approximately $27 million from 2012.

On July 1, 2012, the Company submitted to the OPUC the results of its PCAM for 2011 based on an updated regulated earnings test, which resulted in a revised refund to customers of approximately $6 million. On October 24, 2012, the OPUC issued an order approving the refund, with the impact to customer prices effective January 1, 2013. For further information, see Power Operations, within the Operating Activities section of this Overview, above.

Renewable Resource Costs - Pursuant to a renewable adjustment clause mechanism (RAC), PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The Company may submit a filing to the OPUC by April 1st each year, with prices expected to become effective January 1st of the following year.

In March 2012, PGE submitted a filing for the installation of a small solar facility, which requested a nominal credit to customer prices for a one-year period beginning January 1, 2013, resulting from the gain on the sale and lease-back transaction directly related to the project.

The Company collected $22 million under the RAC as a result of a tariff the OPUC had previously approved for recovery over a one-year period that ended December 31, 2011 for eligible deferred costs and a return on the Company's investment related to Biglow Canyon Phase III and a residual balance from the previous deferral of Biglow Canyon Phase II.

Decoupling - The decoupling mechanism is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The mechanism provides for customer collection (or refund) if weather adjusted use per customer is less (or more) than the levels approved in the Company's most recent general rate case.

            For the nine months ended September 30, 2012, the Company has
             recorded an estimated collection of $1 million. Any estimated refund
             to, or collection from, customers for the 2012 year would begin June
             1, 2013.

During 2011, PGE recorded an estimated refund of $2 million that is being provided to customers

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over a one year period that began June 1, 2012, as weather adjusted use per customer was greater than levels projected in the 2011 General Rate Case.

            For 2010, the Company recorded an estimated collection of $8
             million, as weather adjusted use per customer was less than levels
             included in the 2009 General Rate Case. After review, the OPUC
             approved collections from customers over a one-year period that
             ended May 31, 2012.

Refund of tax credits - In 2011, PGE provided credits to customers for accumulated tax credits related to the Independent Spent Fuel Storage Installation (ISFSI) located at the Trojan site. The discontinuance of the customer credits on January 1, 2012 had the effect of increasing the Company's annual revenues by approximately $18 million.

Critical Accounting Policies

PGE's critical accounting policies are outlined in Item 7 of the Company's . . .

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