How the new standards affect utility balance sheets.
Bente Villadsen is a principal, Amit Koshal is an associate and Wyatt Toolson is a senior research analyst at The Brattle Group. The authors acknowledge the assistance of Stephen Fang, Patrick Ringland, Michael J. Vilbert and Fiona Wang. This article expresses the opinions of the authors and not necessarily those of The Brattle Group or its clients.
Over the next year (or years), companies in Canada and the United States will make the transition toward adopting International Financial Reporting Standards (IFRS). These standards will have a significant impact on the reporting requirements and financial disclosures of regulated companies, largely because a regulated company’s financial information is used not only for financial reporting purposes, but also for ratemaking purposes. In particular, most electric, gas, water and pipeline utilities in North America are regulated on a cost-of-service basis, which allows them to recover costs they incur in providing service, including their cost of capital.1 Because cost-of service regulation creates a strong link between the utility’s cost and assets, the measurement of these costs and assets and how they’re reported on the financial statements becomes important.2, 3
The financial reporting requirements of IFRS and GAAP differ in some key ways that affect utilities.4 First, under U.S. and Canadian GAAP, regulatory assets and liabilities are recognized in the financial statements, whereas IFRS has yet to implement specific guidelines for regulatory assets and liabilities.5 As such, the potential effect of removing regulatory assets and liabilities from utilities’ balance sheets merits examination.6 Second, a major difference between U.S. and Canadian GAAP and IFRS is the accounting for depreciation, asset impairment, the potential for revaluations of assets, and the treatment of power purchase agreements. Regulated utilities are capital intensive, so changes in the treatment of long-lived assets will have a substantial impact on regulated companies. Third, IFRS has stricter rules for what IFRS calls “own use” for their purchases of commodities and power. These rules could substantially affect regulated utilities that rely on the normal use and purchase exemption rather than on fair value (derivatives) accounting for these purchases. Finally, IFRS eliminates asset smoothing for pension gains and losses. As a result, companies need to consider how regulatory allowances for pension costs are recovered in rates.
Regulatory Assets and Liabilities
Under current IFRS, regulatory assets and liabilities aren’t recognized and would be removed from many utilities’ balance sheets.7 Only those utilities with traditional cost-of-service regulation would be able to recognize regulatory assets and liabilities. Utilities with revenue and price regulation, or other forms of incentive regulation, would fall under the current guidelines. Utilities are logically concerned about this change as illustrated in a letter to the Securities and Exchange Commission from water utility SJW Corp., which states:
SJW Corp.’s understanding is that the IFRS has no equivalent standard comparable to SFAS 71 and therefore regulated assets and liabilities may not be deferred except in certain rare circumstances. The absence of similar regulatory recognition under IFRS may subject utilities reporting under IFRS to volatility not previously experienced under U.S. GAAP. 8
The International Accounting Standards Board (IASB) is considering a proposal that will allow for regulatory assets but in a more limited sense than SFAS 71.9 If the IASB decides to not recognize regulatory assets and liabilities, the impact on utilities’ balance sheets would be substantial, based on an analysis of 92 electric, gas, and water utilities (see Figure 1). In 2009, decreases in total assets and total equity would have measured approximately $1.4 billion and $800 million, respectively. In percentage terms, total assets would be reduced on average by 12 percent, total liabilities by 9 percent, and total equity by 17 percent (see Figure 2).
Given the reliance of many parties on balance sheet metrics, it’s important to recognize that regulatory assets and liabilities will result in future cash flows. Therefore, investors and analysts will have to adjust forecasted cash flow as well as credit metrics to account for the potential de-recognition of regulatory assets and liabilities. Further, regulatory recognition of utilities’ ability to recover items in future revenues as regulatory assets and be turned into cash sends an important signal to investors; without this information, investors will have to infer it from sources other than the balance sheet.
Depreciation and Asset Retirement
Utilities generally have a large amount of fixed assets that can be divided into many components. The IFRS requirement that assets be depreciated by components likely will create substantial costs for utilities. Currently, most utilities depreciate their assets by classes rather than components, and U.S. and Canadian GAAP allow componentization but don’t require it. Given the age and composition of utility assets, it will be costly to satisfy IFRS’ current requirements and determine a depreciation schedule for components. For example, electric utilities often have large and dispersed generation, transmission and distribution assets, and many such assets last 40 years. Depreciation by components might require a physical inspection and subsequent tracking of components of these assets, which will increase the reporting burden. Similarly, gas distribution and water utilities often have large in-ground distribution systems that would be difficult to depreciate using IFRS’ componentization method. Regulators, such as the Federal Energy Regulatory Commission (FERC),10 and GAAP allow for depreciation by class, so the required analysis of asset components and their useful lives will likely be more detailed than what’s currently required under either GAAP or FERC reporting. As a result, a transition to componentization would impose additional costs on regulated entities and likely on their customers.
The transition to componentization under IFRS might have several consequences affecting regulation. First, it’s possible that the componentization would lead to depreciation rates that differ from those approved by the regulator. Depreciation constitutes a large component of regulated entities’ revenue requirement and provides a large portion of the utilities’ cash flow from operations.11 Therefore, the change could create controversy in rate proceedings. Second, IFRS allows the company to measure a component of its PP&E at fair value upon transition to IFRS, which would result in a mismatch between the traditional original cost based regulation that is common in North America and in financial reporting.
Similarly, U.S. electric utilities report asset retirement obligations of approximately $20 billion to $22 billion, corresponding to 4 to 5 percent of their net utility plant.12, 13 Both IFRS and U.S. GAAP provide for the recognition of costs of dismantling an asset and restoring its site as a liability, with an offsetting amount included in the capitalized cost of the asset. However, the implementation of the two approaches differs. While U.S. GAAP uses an adjusted risk-free rate to discount the liability, IFRS relies on a discount rate that corresponds to the risk of the liability. In addition, IFRS revalues the liability each accounting period.
Impairment and Revaluations
Utility companies are capital intensive and differences between GAAP and IFRS likely will have a significant impact on utilities. The two key differences pertain to asset impairment testing and asset revaluation.
Both IFRS and GAAP require periodic tests of whether assets or liabilities are impaired and thus required to be written down. However, the test for impairment differs. Under current GAAP, asset impairment occurs in a two-step procedure.
In step one, the sum of the undiscounted cash flows that the asset or liability cause is calculated. If this sum is larger than the current book value of the asset or liability, there’s no impairment. If the sum is less than the book value of the asset or liability, then the asset or liability is impaired.
In step two, an impaired asset or liability is written down to the undiscounted sum of the cash flows or net realizable value.
Under IFRS, impairment testing relies on the discounted sum of cash flows that the asset or liability earns or incurs. Since IFRS uses discounted cash flows in the impairment test, it becomes more difficult for an asset (or liability) to pass the test.14 If the asset or liability is impaired, then it’s written down to the discounted sum of the cash flows or its net selling price.
To understand the difference, consider a utility with a plant on its books at $190 million. The utility expects to generate $20 million in cash flows over the next 10 years. Under GAAP, because the total expected cash flows exceed the book value of the plant, no impairment to the asset is needed. Under IFRS, however, one must consider the discounted value of these cash flows. Using a conservative after-tax discount rate of 7 percent, the present value of the plant’s cash flows are approximately $140 million. Consequently, the utility would have to write-down the value of its plant by $50 million (see Figure 3). The likelihood of impairment is positively related to the amount of long-term assets on the balance sheet, as well as the life of these assets. In particular, for firms with longer-lived assets, discounting has a more pronounced effect. That is, discounting cash flows on an asset with 40 years of useful life will have much more of an impact on the net present value than discounting cash flows on an asset with five years of useful life. Infrastructures for electric, natural gas, and water facilities have very long asset lives; therefore impairment of companies in the utilities industry likely will be more significant than impairment of companies in other industries. Further, the utility sector is subject to regulatory and legislative oversight and the useful life of assets might depend on regulatory and legislative developments.
A second consideration is that IFRS allows for upward revaluations of assets, which increases the book value of these assets so they’re more in line with their fair value. In this regard, it’s important to note that carbon legislation could make renewable investments much more valuable. This is an important aspect of regulation as, for example, power plants, pipelines, etc., are only useful if they have regulatory approval to operate. It has been increasingly common for regulators to extend the lives of some long-lived assets, thereby increasing the market value of these assets while the book value remains the same. Companies following IFRS could potentially take advantage of this by adjusting the book value of these assets upwards. Such an option isn’t available for firms following GAAP.
Fair Value for Contracts
Many utilities procure commodities (e.g., electricity) through contracts. If, for example, the contract involves procuring electricity for customers, utilities will often rely on the so-called normal purchases and sale exemption under U.S. GAAP. This allows them to reflect the results of the transaction in income only when the contract has settled—i.e., they can opt out of fair value accounting for these contracts.15 During times of fluctuating commodity prices, opting out of fair value accounting for the procurement of electricity or other commodities is likely to make the utility’s income and assets less volatile. While IFRS has an “own use” exemption, the limitations of own use accounting are stricter than those pertaining to normal purchase and sale. As a result, some utilities that currently rely on the normal purchase and sales exemption likely will need to switch to fair value accounting for some commodities contracts.16 Many power purchase contracts that currently are treated as off balance-sheet operating leases will become on balance-sheet leases, and both the power company and the utility will have to disclose lease related revenues and expenses.
This treatment will result in a “bulking up” of the balance sheet and, because some gains and losses in the fair value of contracts are recognized in income, income might become more volatile.
It’s therefore important that regulators, utilities and other stakeholders consider the potential impact on ratemaking initiatives that involve periodical reviews of realized return on equity. Specifically, it might be necessary to change the determination of whether a utility has earned substantially more or less than intended under an incentive-based mechanism or under any other mechanism that calls for the utility to share earnings in excess of a preset amount with customers. Among the ways to make this determination, utilities can: 1) recognize the increased volatility and therefore increase the band around the allowed return on equity; 2) make adjustments to the fair value component of income for regulatory purposes; or 3) average income over a number of periods to dampen the impact of any one period’s change in fair value. Regardless of the method chosen, it’s important that stakeholders agree how to handle these facets of the ratemaking process in advance of IFRS implementation, so that controversy after the fact can be minimized.
A key issue for utilities in North America is how a switch to IFRS will impact regulatory reporting and decision making.17 Canada is set to adopt IFRS by year-end, and the Securities and Exchange Commission (SEC) continues to support a convergence of U.S. GAAP and IFRS.18 Thus, it’s important that regulated entities prepare for the upcoming accounting changes. To do so, regulated entities, regulators, and other stakeholders need to address the impact of the accounting changes on regulatory policy and practice.
Fundamentally, the transition and convergence to IFRS could affect the calculation of rate base and the revenue requirement. There are two potential solutions to changes in the data upon which regulators base their decisions. Regulated entities could prepare two sets of books, which would be costly and would inevitably lead to controversy as stakeholders review two different sets of financial information. Alternatively, regulatory policy and practice could be modified to rely on IFRS in the same manner as GAAP is used today. Regardless of the policies put in place, neither regulated utilities nor customers should become winners or losers.
If a company decides to prepare two separate sets of books, then it also needs to recognize the associated costs. Companies will have to finance additional software, personnel, and potential legal activity that two sets of books might create. Further, it’s important to take a holistic approach and consider the impact on not only the regulatory environment, but also on the utility’s financial and tax reporting and how this information is used by the financial community, regulators, customers, and other stakeholders.
First, if the regulatory environment will rely on the financials that result from IFRS, it’s important to prepare for a transition and to build a consensus about which areas, if any, need a unique (non-IFRS) treatment. Clearly, if the IASB doesn’t adopt the draft proposal or a similar statement, the largest such issue is regulatory assets and liabilities. If IASB were to adopt the current proposal, a decision would need to be made regarding the treatment of regulatory assets and liabilities for entities subject to regulation other than cost-of-service. Second, if the switch to component depreciation changes the timing of the depreciation amount, how does one ensure that there’s neither a rate shock nor an insufficient cash flow effect on the utility? It may be necessary to create a special mechanism that allows for a phased-in switch to the new depreciation rates. This would smooth out rate changes and thus prevent rate shock if the new rates are higher. Third, because the measurement of the asset retirement obligation will differ from current practice and be revalued each accounting period, stakeholders need to consider how this obligation should be recovered through rates. Fourth, some utilities engage in large procurements for their customers and currently use the normal purchase and sales exemption to opt out of fair value accounting for these contracts. Because IFRS has stricter limitations on what qualifies as a non-fair value contract, stakeholders need to consider how they’ll handle an increased volatility in earned return on equity. Specifically, incentive rate making schemes or earnings tests might require modification.
Finally, because asset impairments and revaluations tend to be discrete events, it’s possible to simply reverse such revaluations for ratemaking purposes. Alternatively, stakeholders could allow such revaluations to impact rate base, but they must avoid asymmetry. In other words, if asset write-downs are reflected, asset write-ups should be as well.
1. The cost of capital is often determined as a recovery of interest paid plus a return on the equity portion of the rate base, which is measured as the net original cost of utility asset used to serve customers.
2. Although regulatory accounting may differ from financial reporting to shareholders, difference are often controversial, and keeping and maintaining several different systems is costly, so if a shift to IFRS causes the financial reporting and the regulatory accounting figures to deviate, it will necessarily impose a burden on customers, regulated companies, and other stakeholders.
3. In contrast, many regulated entities outside North America where IFRS has been implemented, are subject to so-called price caps where the price of service is set, but not in the same direct manner linked to the regulated company’s financial statements. Therefore, some implementation issues are unique to North America while others are elevated.
4. There are many other aspects in which IFRS and GAAP differ beyond the scope of this paper. Other areas that are likely to affect North American utilities include the accounting treatment for contingent liabilities, financial instruments, leases, accounts receivable, and securitization.
5. Regulatory assets are assets whose recovery is contingent upon regulatory approval. For example, recovery of the costs of fuel that exceeded the cost allowed in rates is dependent upon the regulators approval. The excess costs are collected and reported as a regulatory asset until the regulator approves recovery.
6. See, IASB, “Rate-regulated Activities,” Exposure Draft, August 2009 and the notes to the IAS Board meeting on July 21, 2010.
7. Canadian regulators, utilities and consumers have been involved in developing guidelines for the implementation and specifically how to handle the disappearance of regulatory assets and liabilities under IFRS. For example, the Alberta Utilities Commission has issued a report on the issue in which the Commission instructs the utilities to continue accounting for regulatory assets and liabilities for regulatory purposes. As IFRS doesn’t allow the capitalization of costs such as general overhead, pre-operating costs, or training costs, the Commission indicates that one option is to include such items as regulatory assets. Thus, a consequence of the IFRS implementation may be that, for regulatory purposes, the magnitude of regulatory assets increases.
8. SJW Corp. letter to the Securities and Exchange Commission, “Re: File No. S7-20-07 International Financial Reporting Standards,” February 7, 2008.
9. See International Accounting Standards Board, “Exposure Draft, ED/2009/8,” which was last discussed by the Board on July 21, 2010, where further analysis was deemed necessary before adoption could be considered. The chairman also noted a standard seemed unlikely to be in place before Canada adopts IFRS in 2011.
10. See, for example, FERC, “Uniform Systems of Accounts,” ¶22.
11. Historical data from FERC Form 1 for 2000-2009 shows depreciation comprises 7-8 percent of electric utilities regulated revenue (Source: Velocity Suite data).
12. IFRS refers to this as decommissioning.
13. Source: Velocity Suite data from FERC form 1.
14. The discount rate is the market borrowing rate for that company.
15. The details of these rules are provided in FASB’s Section 815-10-15-22 to 815-10-15-51.
16. Such utilities will likely experience more volatile income figures. This has implications if the utility is subject to incentive rate making, where return on equity in excess of a specific number is shared with customers (or if the utility is subject to an earnings test as is the case in, for example, for example, Ohio Am. Sub. S.B. No. 221.).
17. Scott Hartman, “Ready for IFRS?” Public Utilities Fortnightly, January 2009 provides a perspective on steps to take to get ready to implement IFRS in a utility setting.
18. See, Federal Register, “Securities and Exchange Commission: Commission Statement in Support of Convergence and Global Accounting Standards; Notice,” March 2, 2010.