SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had none as of December 31, 2015 and $120 million as of December 31, 2014.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice.

Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors.

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2015, 2014 and 2013.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument.

Electricity and natural gas sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets and were $33 million and $11 million as of December 31, 2015 and 2014, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $63 million and $30 million as of December 31, 2015 and 2014, respectively.

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities, as well as fuel for use in its generating plants. Fuel inventories include natural gas, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

Electric Utility Plant

Capitalization Policy

Electric utility plant is capitalized at its original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period.

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. Costs disallowed for recovery in customer prices, if any, are charged to expense at the time such disallowance becomes probable.

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.3% in 2015, 7.4% in 2014, and 7.5% in 2013. AFDC from borrowed funds was $13 million in 2015, $22 million in 2014, and $7 million in 2013 and is reflected as a reduction to Interest expense. AFDC from equity funds was $21 million in 2015, $37 million in 2014, and $13 million in 2013 and is included in Other income, net.

The Company is constructing the Carty Generating Station (Carty), a 440 MW baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to the Boardman coal plant. As of December 31, 2015, PGE had $424 million, including $41 million of AFDC, included in CWIP for the project. On November 3, 2015, the OPUC issued an order approving settlements reached in PGE’s 2016 GRC filing, including capital costs of up to $514 million, including AFDC, for Carty and that Carty will be included in customer prices when the plant is placed in service, provided that occurs by July 31, 2016.

In 2013, the Company entered into an agreement (Construction Agreement) for engineering, procurement and construction of Carty with Abeinsa Abener Teyma General Partnership (Contractor or Abeinsa). On December 18, 2015, the Company declared Abeinsa in default under multiple provisions of the Construction Agreement and terminated the Construction Agreement. Liberty Mutual Surety and Zurich North America (Sureties) have provided a performance bond of $145.6 million under the Construction Agreement. The Company had required Abeinsa to enter into the performance bond to guarantee satisfactory completion of the project in the event the Contractor failed to fulfill its obligations under the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015. The Company is currently in discussions with the Sureties regarding their obligations under the performance bond. The Company believes that the Sureties will have an obligation under the performance bond to contribute funds towards the completion of Carty. However, the Sureties have not yet made a determination with respect to their obligations.

On January 28, 2016, PGE received notice from the International Court of Arbitration that Abengoa S.A., the parent company of the Contractor, had submitted a Request for Arbitration in which it alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to liability of Abengoa S.A. under the terms of a guaranty in favor of PGE pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the Request for Arbitration and intends to contest the arbitration claim.

As a result of the termination of the Construction Agreement, the transition to a new construction team, and related matters, additional costs are expected to be incurred to complete construction of Carty, including, among other things, costs related to determining the remaining scope of construction, re-performing work performed by the Contractor that did not meet specifications, completing an inventory of materials either on-site, ordered or in transit, preparing work plans for contractors, identifying new contractors, negotiating contracts, procuring additional materials, completing unfinished construction, and removing liens on the property. PGE currently expects the total cost of Carty could range from $620 million to $655 million, including AFDC, and is targeted to be placed in service in July 2016. However, due to uncertainties relating to the transition to the new construction team and any other unknown factors related to the completion of construction, estimated completion date and costs could change. The total project cost would be reduced by any amounts received pursuant to the Sureties’ obligations under the performance bond. However, the amount of any such proceeds remains uncertain and cannot be reasonably estimated at this time.

In the event the total project costs incurred by PGE, net of any amounts received under the performance bond, exceed the OPUC’s approved amount of $514 million, including AFDC, the Company would seek approval to recover the excess amounts in customer prices in a subsequent GRC proceeding. However, there is no assurance that such recovery would be granted by the OPUC. If the Carty placed in service date were to be delayed beyond July 31, 2016, PGE would pursue one or more alternative avenues to obtain OPUC approval for the inclusion of Carty costs in customer prices in future GRC filings. Under such circumstance, the Company might not be able to recover some, or all, of the net revenue requirements for Carty from the date Carty is placed into service until the time approved rates go in effect.

During the year ended December 31, 2013, PGE charged $52 million of costs previously included in CWIP related to the Cascade Crossing Transmission Project (Cascade Crossing), which was originally proposed as a 215-mile, 500 kV transmission project between Boardman, Oregon and Salem, Oregon. Based on an updated forecast of demand and future transmission capacity in the region, PGE determined in the second quarter of 2013 that the original projections of transmission capacity limitations contemplated in the Company’s 2009 Integrated Resource Plan, as acknowledged by the OPUC, were not likely to fully materialize. The Company also suspended permitting and development of Cascade Crossing and charged the related capitalized costs to expense. PGE determined that it would not seek recovery of those costs.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2015, 3.6% in 2014, and 3.7% in 2013. Estimated asset retirement removal costs included in depreciation expense were $32 million in 2015, $57 million in 2014, and $55 million in 2013.

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recent depreciation study was completed for 2013, with an order received from the OPUC in September 2014 authorizing new depreciation rates effective January 1, 2015.

Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):



Generation, excluding thermal:
Hydro	95
Wind	30
Transmission	57
Distribution	45
General	12

When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities.

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $227 million and $191 million as of December 31, 2015 and 2014, respectively, with amortization expense of $38 million in 2015, and $25 million in 2014 and $22 million in 2013. Future estimated amortization expense as of December 31, 2015 is as follows: $43 million in 2016; $40 million in 2017; $39 million in 2018; $33 million in 2019; and $23 million in 2020.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold is based on the average cost method.

Regulatory Accounting

Regulatory Assets and Liabilities

As a rate-regulated enterprise, PGE applies regulatory accounting, which results in the creation of regulatory assets and regulatory liabilities. Regulatory assets represent: i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process; or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as: prices are established by, or subject to, approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices.

Circumstances that could result in the discontinuance of regulatory accounting include: i) increased competition that restricts the Company’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’s regulatory assets is probable.

For additional information concerning the Company’s regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities.

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices 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. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a 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, 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. PGE’s authorized ROE was 9.68% for 2015, 9.75% for 2014, and 10% for 2013.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. The PCAM has resulted in no collection from, or refund to, customers since 2011.

Asset Retirement Obligations

Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheet. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is classified as Depreciation and amortization expense in the Company’s consolidated statements of income.

For additional information concerning the Company’s AROs, see Note 7, Asset Retirement Obligations.

The difference between the timing of the recognition of the AROs’ depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. PGE had a regulatory liability related to AROs in the amount of $45 million as of December 31, 2015 and $39 million as of December 31, 2014. For additional information concerning the Company’s regulatory liability related to AROs, see Note 6, Regulatory Assets and Liabilities.

Contingencies

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

Gain contingencies are recognized when realized and are disclosed when material.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $43 million in 2015, $42 million in 2014, and $41 million in 2013.

Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the time of the last meter read date through the last day of the month, a period which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices.

As a rate-regulated utility, there are situations in which PGE recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “Regulatory Assets and Liabilities” in this Note 2.

Stock-Based Compensation

The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.

Income Taxes

Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $86 million as of December 31, 2015 and 2014 and will be included in prices when the temporary differences reverse.

Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet.

PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which was originally January 1, 2017 for the Company. In August 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (ASU 2014-14) that defers the effective date by one year, although it permits early adoption as of the original effective date. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2014-09.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (ASU 2015-03), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The provisions of ASU 2015-03 are effective for fiscal years beginning after December 15, 2015, or January 1, 2016 for PGE, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The provisions should be applied on a retrospective basis. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle, which includes: i) the nature of and reason for the change in accounting principle; ii) the transition method; iii) a description of the prior-period information that has been retrospectively adjusted; and iv) the effect of the change on the financial statement line items. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation of Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (ASU 2015-15), which clarifies that the SEC staff would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of credit arrangement” given the lack of guidance on this topic in ASU 2015-03. PGE will adopt the amendments contained in ASU 2015-03 and 2015-15 on January 1, 2016, which is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), which removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, such disclosures are restricted only to investments that the entity has decided to measure using the practical expedient. This standard is effective for interim and annual periods beginning after December 15, 2015. PGE will adopt the amendments contained in ASU 2015-07 on January 1, 2016, which is not expected to have an impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory (ASU 2015-11), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. Net realizable value is defined as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” ASU 2015-11 eliminates the guidance that entities consider replacement cost or net realizable value less an approximately normal profit margin in the subsequent measurement of inventory when cost is determined on a first-in, first-out or average cost basis. The provisions of ASU 2015-11 are effective for public entities with fiscal years beginning after December 15, 2016, or January 1, 2017 for PGE, and interim periods within those fiscal years. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2015-11.

In January 2016, the FASB issued ASU 2016-01, Financial Instrument-Overall (Subtopic 825-10), Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01), which enhances the reporting model for financial instruments and related disclosures. The main provisions of the ASU will include: i) requirements to measure equity investments (except those accounted for under the equity method of accounting) at fair value with changes in fair value recognized in net income; ii) simplification of the impairment assessment of equity investments without readily determinable fair values; iii) eliminate the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; iv) requirement to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; v) require an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; and vi) require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or footnotes. The provisions of ASU 2016-01 are effective for public entities with fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, in certain circumstances. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2015-11.

Newly Adopted Accounting Standard

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies financial reporting by removing the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet, and instead requires these amounts to be classified solely as noncurrent. This standard is effective for financial statements issued for annual periods beginning after December 15, 2016. The amendment can be applied prospectively or retrospectively and early adoption is permitted. PGE has opted to early adopt the change in accounting principle on a prospective basis and is reflected as such within the balance sheet for the period ended December 31, 2015. Prior periods were not retrospectively adjusted.