The power (and utility) of IFRS. How will IFRS adoption affect the US Power and Utilities industry?

Transcription

1 The power (and utility) of IFRS How will IFRS adoption affect the US Power and Utilities industry?

2 The backdrop for conversion to IFRS 2 The power (and utility) of IFRS

3 IFRS conversion in the US has been a subject of much debate. Proponents claim that US issuers would be more globally competitive if they were permitted to prepare their financial statements in accordance with IFRS. At the very least, a decision not to adopt IFRS in the US puts the country at risk of being marginalized should the tide of conversion continue outside the US. Though the US adoption of International Financial Reporting Standards (IFRS) has not quite reached burning platform status among US companies, the November 2008 issuance for public comment by the U.S. Securities and Exchange Commission (SEC) of its proposed Roadmap for Conversion to IFRS is a strong indicator that IFRS adoption could become a reality in the not-so-distant future. Indeed, it is the direction in which the rest of the world is moving. More than 110 countries require, permit or base their standards on IFRS, and neighboring Mexico and Canada are slated to adopt in 2011 and 2012, respectively. Here in the US, the SEC s Roadmap proposes conversion dates ranging from 2014 for large accelerated filers to 2016 for nonaccelerated filers, with a very limited early-adoption option as early as 2009 upon meeting certain criteria. While we, as accountants, are naturally interested in the accounting considerations, it is important to note that the effects of IFRS adoption transcend the books. Amid the considerations, implications and consequences of IFRS adoption are opportunities for executives to revisit the way their companies are viewed and evaluated by investors and other key stakeholders. Conversion will not be painless, but it appears there will be benefits for companies after the initial costs of conversion in reduced accounting costs and anticipated lower costs of capital. Furthermore, there will be benefits for investors as a result of increased transparency and global comparability. The experience of investors in Europe, where companies listed in the European Union converted to IFRS in 2005, has been favorable. In this article, we set out seven key issues we believe companies in the US power and utilities industry should consider in assessing the effects of conversion to IFRS from US Generally Accepted Accounting Principles (US GAAP). This narrative is intended to focus on the most salient topics and to stimulate discussion and enhance the planning process that will be essential to a successful conversion. The power (and utility) of IFRS i

4 Contents 1 The effect on regulatory accounting 4 Accounting for long-lived assets 6 Impairment considerations 9 Derivatives and financial instruments 14 Accounting for emission rights 16 Prorata consolidation issues and joint ventures 18 Tax considerations 20 Next step: necessary planning and transition 22 Americas Power & Utilities Center ii The power (and utility) of IFRS

5 The effect on regulatory accounting Accounting for the economic effects of regulation has been an integral part of the power and utilities industry s accounting and financial reporting since the 1962 Addendum to Accounting Principles Board Opinion No. 2. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), is the codification in US GAAP of the basis for these long-standing industry accounting practices. Currently, IFRS does not specifically address accounting for the effects of regulation. As a result, the general principles defining assets and liabilities, as well as other standards, apply. As such, utility companies reporting under current IFRS recognize regulatory assets and liabilities under extremely limited circumstances. For example, some of the items currently accounted for as regulatory assets and liabilities under US GAAP would need to be evaluated in conjunction with the criteria set forth in the International Accounting Standards Board s (IASB s) International Accounting Standard (IAS) 37, Provisions, Contingent Liabilities and Contingent Assets, or IAS 38, Intangible Assets. However, in December 2008, the IASB added a project to its agenda to address Rate Regulated Activities and plans to issue an Exposure Draft in July While the elimination of regulatory accounting under FAS 71 is the most pressing IFRSconvergence issue for US power and utilities companies, a new IFRS standard may be on the horizon that could address or limit the differences discussed in this section. Not recording regulatory assets may have a considerable effect both on a company s financial position and on related compliance with existing debt covenants as currently structured, and as such, will introduce significant volatility into annual financial results. Looking back, we can see the tremendous effect that would have occurred if IFRS had already been in place. When generation assets were deregulated due to restructuring in many states, there were significant write-downs for stranded costs that were allowed recovery as surcharges in the regulated distribution company s rates. These write-downs, for many companies, were in excess of US$1 billion. These amounts were recorded as regulatory assets and generally recovered over a 10-year period in rates. Under current IFRS provisions, the costs would be expensed as incurred and the subsequent cash recovery in rates would be reflected as annual income over the next 10 years. This same effect will apply to the other items normally recognized in financial statements as regulatory assets, such as fuel recoveries, storm damage, environmental remediation and losses on refinancing, to name a few. The power (and utility) of IFRS 1

6 In addition to the methods for accounting for regulatory assets and liabilities, there are a number of accounting practices that are based on regulatory requirements and are therefore unique to the power and utilities industry. Many of these are prescribed in the US by the Uniform System of Accounts that is set forth by the Federal Energy Regulatory Commission (FERC). Power and utilities regulators may not show universal support or acknowledgement of IFRS, as such, it is likely that companies may be required to keep at least three sets of accounting records (US GAAP, regulatory reporting and IFRS) during the initial transition. Some of the more significant areas that may be affected include: Allowance for funds used during construction (AFUDC). In a regulated industry, AFUDC takes the place of capitalization of interest. It has a component that capitalizes the cost of equity on construction projects. This cost is then recovered in rates as part of depreciation. The question is whether (i) that cost of equity is a regulatory asset and therefore not valid capital or (ii) the company capitalizes amounts based solely on actual financing expenses incurred, with any amounts in excess of the equity component not recorded but maintained as a statutory amount for regulatory reporting only. IFRS currently addresses the capitalization of interest but does not allow for the capitalization of equity. Overhead costs capitalized on construction projects. Overhead costs in the industry are calculated on a fully allocated cost basis. In other industries, they are generally capitalized on an incremental basis. Again, this accounting practice is prescribed by the Uniform System of Accounts, with the amounts capitalized and recovered as depreciation in rates over the life of the asset. IFRS does not allow for the capitalization of general administrative and overhead costs. In addition, there is likely to be continued subjectivity in determining what costs are directly allocable to a project, including such costs as project management and oversight. Consistency with FERC. Financial reporting for the industry in the US has historically been consistent with the reporting prescribed by FERC. Prior to the industry restructuring in the 1990s, all companies presented their balance sheets with Property, Plant and Equipment (PP&E) as the first item. The income statement was presented with the concept of above and below the line. This practice began to change in the 1990s, with many financialstatement presentations conforming to general commercial industry. But even today, many of the US SEC registrants maintain the traditional financial-presentation practices. These practices are not consistent with the presentation requirements of IFRS. Asset retirements. Accounting for asset retirements has also been prescribed in the Uniform System of Accounts. In a regulated industry, when assets are retired, the full cost of the asset is charged to accumulated depreciation, together with any related cost of removal. Then, any salvage is credited to accumulated depreciation. Depreciation rates are periodically adjusted for any differences that may be created by this accounting. Again, these amounts are collected through rates charged to customers. IFRS does not allow such handling and would require gain or loss to be recorded upon disposal, with cost of removal being expensed as incurred. However, if the retirement obligation meets the criteria for being recorded as of the date of asset acquisition and, therefore, for being included in the cost of the asset and subsequently depreciated, then treatment under US GAAP and IFRS would be similar. Currently, IFRS does not specifically address accounting for the effects of regulation. As a result, the general principles defining assets and liabilities, as well as other standards, apply. As such, utility companies reporting under current IFRS recognize regulatory assets and liabilities under extremely limited circumstances. 2 The power (and utility) of IFRS

7 Contributions in aid of construction. A common occurrence in the industry is contributions in aid of construction. These contributions may arise from developers contributing property, customers paying for line extensions or underground service, and governments seeking line relocations. These contributions are recorded as a reduction in the cost of the asset. The IASB s International Financial Reporting Interpretations Committee (IFRIC) has decided that an obligation must be recognized for a transfer of an asset from a customer (gross reporting). IFRIC 18, Transfers of Assets from Customers, was issued in January Gross reporting is contrary to the Uniform System of Accounts. The accounting for government grants is specifically addressed in IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, and sets forth the accounting guidance for both balance sheet presentation and income recognition. Each of the items discussed above deals with common industry accounting practices that are prescribed by the regulator and may be acceptable under US GAAP only because of rate setting and the related accounting for the effects of regulation. Adoption of IFRS may make rate setting, and the related books and records that are maintained, look, feel and seem like statutory reporting. Public reporting will be based on IFRS, while separate books and records would be maintained to support regulatory accounting. The power (and utility) of IFRS 3

8 Accounting for long-lived assets 4 The power (and utility) of IFRS

9 The applicable international accounting standard for long-lived assets is IAS 16, Property, Plant and Equipment. Although US GAAP does not have a similarly comprehensive standard, differences exist that will need to be evaluated by US power and utilities companies. IAS 16 allows companies to choose either cost or fair value methods in their accounting for PP&E. In addition, entities adopting IFRS for the first time may elect a one-time revaluation to fair value of PP&E at the date of transition, which is then subsequently deemed the cost of the assets under the cost method. If the company chooses the fair value method, an annual revaluation adjustment is then recorded directly to equity. Most companies that have adopted IFRS have chosen the cost method of accounting for PP&E. Irrespective of which method a company chooses, the asset must then be depreciated, which will require unit-of-account (components) decisions to be made and may lead to extensive record keeping. Component method of depreciation. IAS 16 requires the use of the component method of depreciation when significant components of an asset have differing patterns of benefit. The component depreciation method requires the separation of a capitalized asset into its material components if components of the asset have differing patterns of benefit. This will require a power or utility company to evaluate its plant, transmission and distribution assets in order to determine separate useful lives for such items as boilers, turbines and other significant components. For example, a nuclear generation power plant may have a life of 40 years; however, a turbine, feedwater heater or generation may have estimated useful lives of 10 to 20 years and will have to be evaluated. For power and utilities companies, componentizing PP&E assets will be more difficult than for companies in other industry sectors. This is due to the use of the composite method of depreciation (discussed in greater detail in the following paragraph) and as a result, individual lives and the historical net book value of an asset may not be readily determinable. A detailed analysis and related computations will be necessary to assess the impact of the difference between the component method of depreciation as required by IAS 16 and the composite method of depreciation applied to units of accounting that is being used in most cases. IFRS does not specify what constitutes a component. The componentization under IAS 16 will require significant judgment based on the facts and circumstances relating to each asset. There is a related question with respect to the composite method of depreciation, which is supported by FAS 71. The composite method is typically employed by regulated entities for asset groups, such as poles and wires. At this time, we believe that this method of depreciation does not meet the requirements of component accounting and depreciation required by IFRS. The accounting for PP&E could be the most time-consuming exercise a company may need to undertake upon initial adoption of IFRS. Differences between US GAAP, IFRS and regulatory reporting associated with significant components and related issues with respect to capitalized cost are quite detailed and cumbersome to evaluate. Accounting for major maintenance activities, replacement components and necessary write-offs, as well as the impact of the currently used group depreciation with gain or loss upon disposal, all make this area a difficult undertaking for IFRS conversion purposes. Consequently, we believe that planning for conversion cannot start soon enough. Capitalization of borrowing costs. With the issuance of revision IAS 23R, Borrowing Costs, effective 1 January 2009, companies are required to capitalize borrowing costs on a prospective basis, although retrospective application from any specific date is allowed. It is important to note that there are differences between US GAAP and IFRS with respect to the methods, including the qualifying period for capitalization and measurements used to compute the amount of costs to be capitalized, these differences will need to be understood for purposes of complying with IAS 23R. There is also a key difference with regulatory reporting whereby borrowing costs are allowed to be capitalized (AFUDC) in accordance with US GAAP s SFAS 71 that currently are not permitted by IFRS. Asset retirement obligations. Similar to US GAAP, IFRS requires the estimated costs of obligations to dismantle, remove and restore items of PP&E to certain minimum standards (related to nuclear plants, restoring sites back to previous condition, etc.) to be capitalized as part of an asset s cost. The accounting for the effect of changes in the initial measurement of such obligations is set forth in IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities. Deemed cost. The IASB recently issued an exposure draft proposing amendments to IFRS 1, First-time Adoption of International Financial Reporting Standards. The proposed amendments provide additional exemptions from the full retrospective application of IFRS that have particular application to regulated industries. As noted previously, US GAAP currently permits an entity to include, in the cost of its PP&E, amounts that do not qualify for capitalization under IFRS, such as the equity component of AFUDC, certain overheads and removal of salvage costs, which are capitalized for US GAAP purposes through regulatory accounting. The proposed amendment would allow entities to elect to use the carrying amount, under a company s previous US GAAP at the date of transition, as the deemed cost if it is otherwise impracticable (as defined in IAS 8) to meet the requirements of IFRS 1. This exemption would be applied individually to each rate regulated asset, that is, it is not a blanket exemption). When this exemption is used, an impairment test also would be performed on the asset at transition date. The power (and utility) of IFRS 5

10 Impairment considerations A cash-generating unit is defined by IAS 36 as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The IASB decided that under IAS 36, Impairment of Assets, the assessment of impairment should be triggered by changes in facts and circumstances. IAS 36 outlines how an entity, once it determines that an asset is impaired, then measures, presents and discloses that impairment in its financial statements, subject to special requirements with respect to the level at which impairment is assessed. An asset (other than goodwill or an intangible asset with indefinite life) should be assessed for impairment when facts and circumstances suggest that the carrying amount of an asset may exceed its recoverable amount. Under IAS 36, one or more of the following facts and circumstances may indicate that an entity should test its assets for impairment: The carrying amount of the net assets of the entity or power plant exceeds its fair value A significant adverse change in the market in which a plant operates occurs, such as a lack of fuel supply in the geographic area to which the asset is dedicated Significant changes in the extent, or manner, an asset is used or expected to be used; for example, if a power plant changes from a base-load, full-capacity plant to a peaker plant, future cash flows may not fully recover the carrying amount of the asset Unlike US GAAP, undiscounted cash flows resulting in a one-step impairment process are not in accordance with IFRS (IAS 36). Once a triggering event is determined to have occurred, the company will immediately evaluate the recoverable amount of the asset and compare it to its carrying amount. Recoverable amount, as defined by IAS 36, is the higher of fair value less cost to sell and value in use. Considerations for cash-generating units. Under IAS 36, an entity is required to test individual assets for impairment. However, if it is not possible to estimate the recoverable amount of an individual asset, the entity should instead determine the recoverable amount of the cash-generating unit to which the asset belongs. In determining appropriate cash-generating units, an entity will need to consider the following issues: How does management monitor the entity s operations (such as individual plants or areas)? Is there an active market for the output of the plant? Are there plants that are operated as a complex through the use of shared infrastructure? Are there stand-alone plants that operate on a portfolio basis? The IASB decided that cash-generating units should not be aggregated for asset impairment testing (other than goodwill). Therefore, an entity should determine an accounting policy for allocating power and utility assets to cash-generating units for the purpose of assessing such assets for impairment. 6 The power (and utility) of IFRS

11 Possible reversals of impairment loss under IFRS. Any impairment loss that has been recognized in accordance with IAS 36 needs to be reconsidered when there are external or internal indicators that the loss recognized in previous periods may no longer exist or may have decreased because factors that previously gave rise to the impairment have changed. However, this does not include impairment losses on goodwill, which cannot be reversed. To the extent that this impairment loss on the same revalued asset was previously recognized as an expense in the income statement, a reversal of that impairment loss is recognized in the income statement. A separate consideration includes a situation where a regulator disallows certain capitalized costs to a plant to be included in the cost-recovery formula. Under current US GAAP (Paragraph 7, FAS 90, Regulated Enterprises Accounting for Abandonments and Disallowances of Plant Costs), this amount would be written off to the income statement. However, assuming that the plant s recoverable value is in excess of its carrying amount, no impairment would exist under IFRS. In contrast to existing US GAAP accounting methods, some or all of an impairment loss (except for impairment related to goodwill) may be reversed under IFRS. As a consequence, if there are any indications that a previously recognized impairment has not occurred or has been reduced, it is necessary to redetermine the recoverable amount (i.e., the higher of fair value less cost to sell and value in use) so that the reversal can be quantified. The power (and utility) of IFRS 7

12 8 The power (and utility) of IFRS

13 Derivatives and financial instruments The power and utilities sector uses various financial instruments in its operations. Not only are financial instruments used to manage cash flows, but they also are used to lock in future transactions related to commodities, currencies and interest rate risks to which a company is exposed. Under US GAAP, companies account for these instruments using FAS 133, Accounting for Hedging and Derivatives Activities. Under IFRS, companies account for these instruments using IAS 39, Financial Instruments: Recognition and Measurement. There are various differences between the two standards that senior executives and accountants need to understand in order to apply IAS 39 to a company s existing financial instruments. The power (and utility) of IFRS 9

14 Definition of a derivative When FAS 133 was drafted, a definition of a derivative was developed based on characteristics rather than by identifying specific types of instruments. While IAS 39 provides a definition of a derivative, the definition differs from the one in FAS 133. Under FAS 133, a derivative is defined as a financial instrument with the following attributes: An underlying variable and a notional amount No or little initial net investment Terms that permit or require net settlement While IAS 39 has a similar definition, the derivative definition includes reference to settlement as opposed to net settlement. IAS 39 also does not require a notional amount for an instrument to be a derivative. Under IFRS, the first step is to determine whether a contract is actually within the scope of IAS 39, followed by the determination of what type of financial instrument it is. A commodity contract is typically a derivative because of its definition: Its value changes in response to a change in a specified underlying variable (such as a commodity price). No initial net investment (or one that is smaller than) would be required for other types of contracts expected to have a similar response to changes in market factors. It is settled at a future date (including physical settlement). Based on the definition of a derivative in IAS 39, there could be more commodity physical or financial instruments considered as derivatives due to the noted differences related to settlement and a notional. One exception is contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a nonfinancial item in accordance with the entity s expected purchase, sale or usage requirements. A written option to buy or sell a nonfinancial item that can be settled net either in cash, with another financial instrument or by exchanging financial instruments is also within the scope of IAS 39. Such a contract cannot be entered into for the purpose of the receipt or delivery of the nonfinancial item in accordance with the entity s expected purchase, sale or usage requirements. Exception to derivative accounting FAS 133 permits a company to scope out certain transactions that meet the definition of a derivative. This exception, known as Normal Purchase Normal Sales (NPNS), is very common in the industry due to the nature of how a company transacts in the marketplace. In FAS 133, NPNS is expressed for US GAAP purposes as follows: The normal purchases and sales exception is available for contracts that provide for the purchase or sale of something other than a financial instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. 10 The power (and utility) of IFRS

15 IAS 39 uses the concept of the own-use exemption, which is similar in nature to the NPNS exception of FAS 133. In IAS 39, the own-use exemption applies to those contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a commodity in accordance with an entity s expected purchase, sale or usage requirements. Under IAS 39, the entity s past practice and trends are critical to the evaluation and the ability to net settle a contract, and lack of conformance may disqualify it from own-use treatment. This point, if IFRS were adopted, could present a significant change in accounting, which currently typically accounts for physical commodity contracts as NPNS. Since commodities are generally readily convertible to cash, most contracts would have to be accounted for at fair value unless these contracts met the criteria of the own-use exemption. Under FAS 133, applying NPNS is a voluntary matter. As such, a company can effectively choose which contracts it will account for as a derivative and mark to market through earnings instead. Under IAS 39, if the contract meets the criteria of the own-use exemption, the contract will not be subject to fair value accounting and there is no election to account for the contract under the ownuse exemption. Volumetric flexibility in contracts It is industry practice, in certain circumstances, to include volumetric flexibility in contracts to make certain that buyers have access to additional supplies in the event of increased demand or consumption. IAS 39 states that a written option cannot qualify for the own-use exemption if the contract includes the right for the buyer to request additional quantities for a certain price. Therefore, such contracts need to be analyzed to determine whether the volumetric flexibility constitutes a written option from the seller s perspective rather than the purchaser s. If the volumetric flexibility does represent a written option, the ownuse exemption may not be applied and the contract will be within the scope of IAS 39. Take-or-pay contracts Utilities enter into long-term take-or-pay contracts whereby the buyer is obligated to take the quantity stated or pay for the amount not taken. If the amount taken is less than the minimum stated in the contract, the buyer is obligated to pay the seller for the shortfall. This payment may constitute a net settlement and puts it within the scope of IAS 39. An additional consideration is whether the arrangement would constitute a lease as defined in IFRIC 4, Determining Whether an Arrangement Contains a Lease, which is similar to the guidance set forth in the Emerging Issues Task Force (EITF) Issue No. 01-8, Determining whether an Arrangement Contains a Lease. Day one profits If a contract does not qualify for the NPNS exception under FAS 133, it has potential to create a day one profit. Under US GAAP, it is appropriate to account for gains or losses created on day one. Day one gains are created from the difference between the fair value of the contract at inception and the entry price (transaction price) of the contract. These gains are accounted for regardless of whether the inputs into the valuation methodology are based on observable or unobservable inputs. This concept is fairly different under IAS 39. Day one gains are recognized only if the fair value is based solely on prices quoted in active markets or based on a valuation A contract is within the scope of IAS 39 if the terms of the contract allow a counterparty to buy or sell a nonfinancial item that can be settled net in cash or in return of (or exchange of) another financial instrument, as if the contracts themselves were financial instruments. The power (and utility) of IFRS 11

16 technique that uses observable market data only. When the term of the instrument extends beyond the period for which there is an active market in the underlying item, partial recognition of the day one gain may be appropriate, taking into account the specific characteristics of the contract. Embedded derivatives Long-term commodity purchase-andsale contracts may contain complicated contractual terms, such as: Pricing clauses based on indices or the prices of similar commodities Currency denominations that are different from the functional currencies of the contracting parties involved These contractual terms may represent an embedded derivative. An embedded derivative is a component of an instrument in a nonderivative host contract; it works in such a way that some of the cash flows of the combined instrument vary similarly to how a stand-alone derivative itself varies. This means it causes some or all of the cash flows required by the contract to be modified according to a specified commodity price, foreign-exchange rate, index, price, rate or other underlying variable. Under IAS 39, the general rule is that an embedded derivative has to be: Separated from its host contract Accounted for separately like a stand-alone derivative at fair value (as an ongoing balance sheet item) However, there are exceptions to this general rule. The most important exception occurs in relation to long-term purchase contracts. An embedded derivative does not need to be separated from its host contract when the economic characteristics and risks of the embedded derivative are closely related to those of the host contract. Unfortunately, IAS 39 does not provide a clear definition of closely related. Rather, it illustrates the intention by providing a series of situations where an embedded derivative is, or is not, regarded as closely related to the host contract. Making this determination can prove very challenging, especially for energy contracts. In addition, if the host contract is fair-valued, then the embedded derivative does not need to be separated. During its December 2007 meeting, the IASB discussed its 2008 annualimprovements process. The IASB proposes to amend IAS 39 to clarify that a contract which is not within the scope of the standard cannot be fair-valued in its entirety if it contains an embedded derivative. Under US GAAP, an embedded derivative that is not considered clearly and closely related disqualifies the entire contract from NPNS and the entire contract is considered a derivative. Hedging relationships Economic hedging is important to a utility company in order to mitigate the price risk related to commodities and foreign currencies, as well as to mitigate interest rate risk. Hedge accounting seeks to recognize gains and losses on a hedging instrument in Derivative transactions are accounted at fair value through the income statement, unless cash flow hedge accounting is elected, in which case the amounts are deferred. In order for a hedge to qualify for hedge accounting, all of the following conditions must be met under IAS 39: 1. The hedging relationship must be designated and documented, together with the company s risk management objective and strategy in undertaking the hedge. 2. The hedge must be expected to be highly effective. 3. For cash flow hedges, a forecast transaction that is the subject of the hedge must be highly probable and must present an exposure to variations in cash flows that could ultimately affect profit or loss. 4. The effectiveness of the hedge can be reliably measured. 5. The hedge must be assessed on an ongoing basis and determined to actually have been highly effective throughout the financial reporting periods for which the hedge was designated. 12 The power (and utility) of IFRS

17 the same period(s) and/or in similar line items in the financial statements as gains or losses on the hedged position. In similar fashion to FAS 133, international accounting standards do not prescribe any method for assessing hedge effectiveness. Methods used to assess and measure hedge effectiveness include regression analysis, the dollar-offset method and scenarios-based value-at-risk models. For prospective and retrospective tests, different models may be applied. However, measurement of ineffectiveness would be based on the dollar-offset method. This is relevant for recognizing the appropriate amount of ineffectiveness in profit or loss for cash flow hedges. Under SFAS 133, a company may elect to measure an interest-rate hedge relationship using the short-cut method. Using this method, both the hedge and the hedged item s critical terms match and are reviewed when financial information is reported. Under IAS 39, this method is prohibited and a company must assess and measure effectiveness. In similar fashion to FAS 133, international accounting standards do not prescribe any method for assessing hedge effectiveness. Methods used to assess and measure hedge effectiveness include regression analysis, the dollar-offset method and scenarios-based value-at-risk models. The power (and utility) of IFRS 13

18 Accounting for emission rights In recent years, the increasing worldwide focus on climate change and the need to mitigate the impact of human activity on the environment has led to efforts to cut the level of emissions generated by power and utilities companies and industry in general. Meanwhile, the accounting for emission rights and related emissions has been a highly debated issue. To date, however, no authoritative accounting literature on the subject (either IFRS or US GAAP) has been issued, and industry practice has been mixed. The IASB issued an interpretation that dealt with the topic, IFRIC 3, Emission Rights, but this Interpretation was withdrawn. Recently, the IASB has added an Emission Trading Scheme project to its agenda. At its May 2008 meeting, the IASB tentatively decided that the scope of the project will address the accounting for all tradable emission rights and obligations and for activities for receiving tradable rights in the future (for example, Certified Emission Reductions (CERs). The primary questions on accounting for emission rights are: Should emission rights be recorded at cost or at fair value? Should these rights be classified as intangible assets or as inventory? How should obligations to remit emission rights be accounted for? In addition, companies need to determine the potential implications of any existing forward contracts, considering current rights owned, either granted free of charge from applicable regulatory agencies or purchased on the open market. To make this evaluation, companies also need to determine whether they are traders of emission rights. The presentation of gains from the sale of emission allowances also must be evaluated. A view has developed that a forward contract to sell emission rights is considered a contract on a nonfinancial item and, if solely related to selling rights in excess of those that have been granted and are not required in operations, the forward contract has not been entered into for trading purposes. As such, it is not within the scope of IAS 39. For all forward contracts to sell emission rights, paragraph 5 of IAS 39 must be applied to determine whether the contracts are within its scope. When an entity trades derivatives based on emission rights, those derivatives fall within the scope of IAS 39 and are accounted for at fair value through profit or loss, unless they hedge the fair value of the emission rights granted to the entity or qualify for the own-use exemption. When an entity holds emission rights for own use and has a trading department that trades in emission rights, the entity should account separately for emission rights held for own use and those held for trading. Due to the lack of specific guidance on the accounting treatment of emission rights and related liabilities, three alternative accounting methods have been identified: The method described in the withdrawn IFRIC 3 The net liability method The government grants approach The method set forth in the withdrawn IFRIC 3 specified the accounting for companies participating in government schemes aimed at reducing greenhouse gas emissions. It proposed that companies account for the emission allowances they receive from governments as intangible assets, recorded initially at fair value, with a corresponding credit to deferred income. This deferred income would then be released to income on a systematic basis (typically based on usage) over the compliance period for which the emission rights were issued. IFRIC 3 also would have required companies, as they produce emissions, to recognize a liability for the obligation to deliver allowances to cover those emissions. The When considering classification, most companies that have adopted IFRS have classified emission rights as intangibles. However, in a way that is somewhat uncharacteristic of the classification as an intangible, there have been instances in which the rights have been allocated between current and long term, based on the estimated usage. 14 The power (and utility) of IFRS

19 provision would be measured at the market price of allowances to cover emissions up to the balance sheet date. Under the net-liability method, a provision is recognized only at the point where actual emissions exceed rights granted and are still held. If this method is applied, granted allowances must be measured at their nominal amounts (which is nil for rights granted for free). Most utility companies in Europe currently apply the net-liability method. The liability can be measured either at the market price at the balance sheet date or at the carrying value of rights held the carrying-value method. In this case, the entity may measure the provision, to the extent that it holds emission rights, based on the carrying value of the rights it holds. The provision in excess of the rights held is measured at fair value to reflect its obligation to purchase further emission rights. If the government-grants (or fair-value) approach is chosen, the rights are recorded as an asset at fair value, with a corresponding item of deferred income. This deferred income is then released to income on a systematic basis, consistent with the requirements of IFRIC 3. A provision is recorded for actual emissions produced. The provision may be measured based on either the carrying-value method or the current market price of emission allowances. When an entity measures the provision at fair value at each balance sheet date, the entity may elect to classify the emission rights purchased as reimbursement rights in respect of the provision. This means that the emission rights held to match an existing liability can be remeasured to fair value (to match the liability), even if there is no active market. Remeasuring emission rights as reimbursement rights would have the same effect on the income statement as measuring the liability using the carrying amount method and not remeasuring emission rights. When considering classification, most companies that have adopted IFRS have classified emission rights as intangibles, which seems to be the most common practice, although classification as inventory is also acceptable. However, in a way that is somewhat uncharacteristic of the classification as an intangible, there have been instances in which the rights have been allocated between current and long term, based on the estimated usage. As a result of the lack of existing literature, it is expected that power and utilities companies would specifically disclose their general accounting policies for classification and valuation in accounting for emission rights. The power (and utility) of IFRS 15

20 Pro rata consolidation and joint ventures 16 The power (and utility) of IFRS

21 Joint ventures, both incorporated and nonincorporated, are common in the power and utilities sector; however, not all arrangements that are casually described as joint ventures necessarily meet the definition of a joint venture under IFRS. Although joint ventures take many forms and structures, IAS 31, Interests in Joint Ventures, specifies three broad types: Jointly controlled operations Jointly controlled assets Jointly controlled entities IAS 31 emphasizes joint control, whereas IAS 28, Investment in Associates, embraces the principle of the investor having significant influence, meaning that the investor participates in the financial and operating policy decisions of the investee. However, such influence need not result in control or joint control over those policies. Presence or absence of a contract. Activities that have no contractual arrangement to establish joint control are not joint ventures for the purposes of IAS 31. In other words, if two entities, A and B, set up a third entity, C, in which A and B each hold 50% of the equity, C will not, by virtue of the relative shareholdings alone, be a joint venture of A and B for the purposes of IAS 31. There needs to be an agreement for unanimous decision-making on key matters although this might automatically flow from the general provisions of corporate law in the jurisdiction concerned. In the absence of a contractual arrangement to establish joint control, an investment cannot be a joint venture and should be accounted for either as a subsidiary under IAS 27, Consolidated and Separate Financial Statements, as an associate under IAS 28, or as a financial asset under IAS 39. Jointly controlled assets. A Jointly Controlled Asset (JCA) is the most common form of joint venture in the power and utilities sector. JCAs involve the joint control, and often joint ownership, of one or more assets contributed to or acquired for the joint venture and dedicated to the purposes of the venture. The assets are used to obtain benefits for the venturing parties. Each may take a share of the output from the assets and bear an agreed-upon share of the expenses incurred. Such ventures do not involve the establishment of an entity or financial structure separate from the parties themselves, and as a result, each party has control over its share of future economic benefits through its share in the jointly controlled asset. A JCA is similar to an undivided interest as used in US GAAP, which is a fractional ownership interest in the entire plant and related asset group. The accounting for a JCA under IFRS is similar to the accounting currently applied under US GAAP (EITF Issue No. 00-1, Balance Sheet and Income Statement Display under the Equity Method for Investments in Certain Partnerships and Other Unincorporated Joint Ventures). IAS 31 directly addresses JCAs. It requires a venturing party to recognize the following in its financial statements: Its share of the jointly controlled assets, classified according to the nature of the assets (e.g., a share in a jointly controlled nuclear power plant should be shown) within PP&E rather than as an investment Any liabilities that it has incurred Its share of any liabilities incurred jointly with the other venturing parties Any income from the sale or use of its share of the output of the joint venture Its share of any expenses incurred by the joint venture Any expenses that it has incurred in respect of its interest in the joint venture The IASB believes that this treatment reflects the substance, the economic reality and (usually) the legal form of the joint venture. However, it should be noted that the classification of a venture as either a jointly controlled asset or a jointly controlled entity is largely form-driven. Jointly controlled entities. In contrast to a jointly controlled operation or a jointly controlled asset, a Jointly Controlled Entity (JCE) is a joint venture that involves the establishment of a corporation, partnership or other legal entity in which each venturer has an interest. The entity operates in the same way as any other entity, except that a contractual arrangement between the parties establishes joint control over the entity s economic activity. IAS 31 maintains that many jointly controlled entities are similar in substance to jointly controlled operations or jointly controlled assets. IAS 31 permits two methods of accounting for jointly controlled entities: Proportionate consolidation The equity method The IASB recently issued Exposure Draft 9, Joint Arrangements, which is intended to replace IAS 31. Exposure Draft 9 proposes that proportionate consolidation of jointly controlled entities no longer be allowed; however, it is not expected that issuance of the final standard would generally affect the accounting for jointly controlled assets and operations. The power (and utility) of IFRS 17

22 Tax considerations 18 The power (and utility) of IFRS

23 FAS 109, Accounting for Income Taxes, and IAS 12, Income Taxes, provide the guidance for income tax accounting under US GAAP and IFRS, respectively. Each of these pronouncements requires entities to account for both the current and expected future tax consequences of events that have been recognized. Expected future tax consequences (that is, deferred taxes) are measured by reference to temporary differences between the carrying amount of an asset or liability in the financial statements and the amount attributed to that asset or liability for tax purposes. Deferred tax liabilities for temporary differences arising from nondeductible goodwill are not recorded under either approach, and the tax effects of items accounted directly to equity during the current year are also allocated directly to equity (although FAS 109 does not allow backward tracing to prior years). Neither IFRS nor US GAAP permits discounting of deferred taxes. While presently differences between IFRS and US GAAP exist in accounting for income taxes, an exposure draft published in March 2009 has addressed some of these differences. Specific examples of these differences include: The determination of tax basis The recognition of deferred tax assets and assessment of any related valuation allowance The classification of deferred taxes in the financial statements In general, further IFRS convergence is likely with respect to these differences. IFRS has not yet adopted specific guidance similar to US GAAP on uncertain tax positions (FIN 48, Accounting for Uncertainty in Income Taxes, under US GAAP). The exposure draft addresses uncertain tax positions, but the proposed approach is different from FIN 48. This approach would require recognition of tax benefits based on the technical merits of the tax positions determined by the probability-weighted average of the possible outcomes, but without an adjustment for detection risk. Of course, all financial-statement changes as a result of a conversion to IFRS may have some tax impact, since the financial reporting basis of accounting may change. For example, as previously discussed, IFRS does not have similar accounting for regulatory assets and liabilities as provided under FAS 71 in US GAAP. Deferred tax accounting related to regulatory assets and liabilities may change, as there will be no deferred tax for the regulatory impact of temporary differences that are flowed through to ratepayers. Taking things one step further, the conversion to IFRS will have implications beyond financial reporting; consequently, it is important for companies to assess all of the potential effects. As companies consider the effect of adopting each standard in IFRS, they also should identify the related tax-reporting and compliance outcomes. In addition to the tax effects of changes to the balance sheet and accounting income, tax considerations include the potential impact on current or future tax-return positions, (e.g., positions requiring book-tax conformity). All companies need to consider the impact on accounting methods for tax reporting and make sure that the appropriate book-to-tax differences may be isolated for proper income tax compliance. The corporate information systems that currently support both direct and indirect tax requirements may have to be changed to make certain that tax planning, accounting and compliance processes continue to operate effectively and efficiently with the new IFRS-based information. The power (and utility) of IFRS 19

24 Next step: necessary planning and transition In the end, a high degree of awareness and thoughtful examination starting now could result in a smoother transition later. In the US, the adoption of IFRS will have far-reaching implications for a number of systems, entities and affected parties. These include capital markets, lending institutions, the taxing authorities and other regulatory bodies. These various market participants will offer their viewpoint on adoption and the proposed timetable. It is currently unclear how federal, state and local regulators will view IFRS and what it will mean for future regulatory reporting. Since it is likely that during the transition to IFRS companies will need to maintain three separate accounting records to accommodate or reflect IFRS, regulatory reporting and US GAAP, it is imperative 20 The power (and utility) of IFRS

25 that companies start planning now. On the detail level, major impact items should be identified and decided. Companies will need ample transition time to modify their systems, controls and reporting processes. They will also need to train staff on the new standards, as well as educate investors and analysts about the impact the new reporting system will have on the financial statements. Leading companies will need to evaluate the effect on corporate finance, management reporting, performance indicators for employee compensation and benefits, and tax planning and reporting requirements. Certain tax provisions could negatively affect the attractiveness of a conversion to IFRS, such as the prohibition under IFRS of the Last In, First Out (LIFO) method of inventory costing. In some instances, the less-detailed nature of IFRS will likely cause much debate and perhaps some frustration in the power and utilities sector. Companies could encounter issues that range from recognizing the value of and accounting for any physical assets, such as expensive power-generation equipment, to accounting for high-cost repairs and retrofits essential to keep the equipment running. In the end, a high degree of awareness and thoughtful examination starting now could result in a smoother transition later. While we hope this narrative of the leading IFRS considerations was informative, it is important to note that the thoughts and analysis we have provided represent just an overview of concerns relevant to the US power and utilities sector. We invite you to contact your Ernst & Young representative for a more thorough discussion of IFRS and what it means to you. The power (and utility) of IFRS 21

26 Americas Power & Utilities Center About the Ernst & Young Power & Utilities Center In a world of uncertainty, changing regulatory frameworks and environmental challenges, utility companies need to maintain a secure and reliable supply, while anticipating change and reacting to it quickly. Ernst & Young s Global Power & Utilities Center and the Americas Power & Utilities Center bring together a worldwide team of professionals to help you achieve your potential a team with deep technical experience in providing assurance, tax transaction and advisory services. Americas Power & Utilities Center and IFRS contacts Bob Ford Americas Power & Utilities Leader Philadelphia, PA robert.ford@ey.com The Centers work to anticipate market trends, identify the implications and develop points of view on relevant industry issues. Ultimately it enables us to help you meet your goals and complete more effectively. It s how Ernst & Young makes a difference. 22 The power (and utility) of IFRS

27 Scott Hartman Sector IFRS contact Philadelphia, PA Ken Marshall Americas IFRS Markets Co-leader New York, NY Danita Ostling Americas IFRS Technical Leader New York, NY Lenora Ausbon-Odom Implementation Director, Americas Power & Utilities Center Washington, DC Gary Birkenbeuel Americas IFRS Markets Co-leader Los Angeles, CA Caryn Pizio Marketing Manager, Americas Power & Utilities Center Washington, DC The power (and utility) of IFRS 23

28 Ernst & Young Assurance Tax Transactions Advisory Ernst & Young is a global leader in assurance, tax, transaction and advisory services. Worldwide, our 135,000 people are united by our shared values and an unwavering commitment to quality. We make a difference by helping our people, our clients and our wider communities achieve their potential. For more information, please visit Ernst & Young refers to the global organization of member firms of Ernst & Young Global Limited, each of which is a separate legal entity. Ernst & Young Global Limited, a UK company limited by guarantee, does not provide services to clients Ernst & Young LLP All Rights Reserved. SCORE No. I00152 Ref. No _BOS