Rate-Base Cleansings: Rolling Over Ratepayers


State PUCs should recognize a refundable regulatory liability for past charges to ratepayers.

Fortnightly Magazine - November 2005

The Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 143 (SFAS No.143) identifies an immediate need for state public utilities commissions (PUCs) to recognize a refundable regulatory liability for past charges to ratepayers for non-legal asset retirement costs.

Although these prior charges resulted in billions of dollars of regulatory liabilities on utilities' generally accepted accounting principles (GAAP) financial statements, they are almost invisible on the regulatory financial statements of the utilities. This is because of the deference shown to state PUCs by the Federal Energy Regulatory Commission (FERC) when dealing with these liabilities. Unless the state PUCs specifically recognize the liabilities, the utilities will have the opportunity to institute a rate-base "cleansing" by transferring ratepayer-fronted money into income.

Regulated public utilities rely on ratemaking hearings rather than a competitive market to establish their prices. A utility's "revenue requirement" quantifies several components summing up to the allowed revenues it will have the opportunity to collect. The "rate base" is the shareholders' investment in utility operations. A "rate of return" applied to rate base yields the "return on investment" component of the revenue requirement. Hence the phrase "rate-base, rate-of-return regulation."

Rate base includes the investment in plant and other assets, net of accumulated depreciation, and ratepayer-provided capital. Accumulated depreciation theoretically measures the amount of "investor-supplied capital" that has been returned by ratepayers. Alternatively, "ratepayer-provided capital" includes items such as accumulated deferred taxes and investment tax credits, which are charges to ratepayers for taxes the utility did not pay. In theory, ratepayers initially "front" these amounts, and then repaid in the form of lower tax expense charges in the future. The is the subtraction of this ratepayer-provided capital from rate base.

Déjà Vu All Over Again

The telephone industry has cleansed its rate base twice. Now regulated electric and other utilities are ready to cleanse their rate bases. In fact, certain electric utilities already have demonstrated their willingness to write off these ratepayer-provided capital amounts. "Write off" is a euphemism for an increase to corporate retained earnings.

To prevent these cleansings, state PUC regulators first must recognize that the utilities have collected enormous amounts for future removal costs, and then declare those amounts to be regulatory liabilities for regulatory and ratemaking purposes.

Although all companies record depreciation expense and concomitantly increase their accumulated depreciation accounts, the process creates substantial controversy in public utility rate proceedings due to the magnitude of the numbers, stemming from the capital intensity of these regulated industries.

Depreciation rates are the vehicle for charging depreciation expense. The higher the depreciation rate, the higher the depreciation expense. Utility depreciation expense increases revenue requirements and therefore drives up utility prices. Depreciation expense is the cause, and the resulting charges to ratepayers are the effect. This article addresses regulatory liabilities resulting from depreciation-rate markups for future removal costs.

When a physical asset is no longer useful, it is retired from service. Asset-retirement costs are incidental to the retirement. Markups for estimated future retirement costs have increased public utility depreciation rates. The marked-up rates produced depreciation charges far in excess of the amount necessary to return capital to investors over the lives of utility assets.

As a rate regulator, a state PUC can impose a refundable obligation. For example, it may increase a public utility's current service rates to recover costs expected to be incurred in the future, with the understanding that if those costs are not incurred, the utility's future rates will be reduced by corresponding amounts. This obligation to pay future costs or refund the excess is a "regulatory liability."1

The Difference Between Legal And Non-Legal AROs

FASB's SFAS No. 143 addresses asset retirement obligations (AROs) associated with long-lived plant. It applies to both regulated and unregulated companies. Legal AROs are "legal obligations that a party is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel."2

When a company has a legal ARO, the discounted fair value of the related asset retirement cost (ARC) is capitalized and depreciated. A legal ARO results in an increased charge to depreciation expense by virtue of the higher asset cost, as long as there is a legal requirement to incur the future cost.

Many utilities do have legal AROs. The obligation associated with the retirement of nuclear plants whereby the company is legally required to perform decontamination activities when the plant ceases operations is a legal ARO. If a utility determines that it has collected too much for a legal ARO decontamination expense, it is required to report the excess collections as regulatory liabilities.

Moreover, SFAS No. 143 also addresses "non-legal" AROs. A non-legal ARO is an estimated future retirement cost for which there is no actual legal obligation or liability.3 SFAS No. 143 requires reporting of non-legal AROs as regulatory liabilities to ratepayers because there is no legal obligation to incur these costs.4 Thus, if a utility either collected too much for a legal ARO or has collected money for non-legal AROs, SFAS No. 143 requires it to report them as regulatory liabilities.

Since the doctrine of promissory estoppel provides substantial leeway in qualifying an ARO as legal, the threshold tests are low. The fact that an ARO is not legal under that doctrine suggests that the obligation is doubtful. By definition, non-legal AROs are not "liabilities"; they are not "probable" future sacrifices of economic benefits.5 Non-legal AROs are ambiguous and they are not even conditional obligations.6 Any conditional obligations, or even promises to spend the money for cost of removal, would qualify as legal AROs.

Yet, regardless of the low threshold, the utility industry still reports billions of dollars of regulatory liabilities resulting from non-legal AROs. The industry acknowledges that it does not have any obligation to remove its plant or to spend the money it has collected from ratepayers for that presumed purpose. Explicitly, it has not promised to spend the money for its intended purpose, and it has recognized that it is not even reasonable to assume that it will incur these future removal costs.

Given these facts, the only reasonable conclusion is that the industry likely never will incur all of the non-legal AROs that it has charged to ratepayers. That is not to say that the industry will not spend money; indeed, it will spend, but only a small portion will go for future removal costs.

Where the Problem Started

The significant magnitude of these regulatory liabilities is the product of the traditional inflated future cost approach (TIFCA), used by utilities to estimate future removal cost. TIFCA marks up depreciation rates for inflated removal-cost estimates. When applied to an ever-expanding gross plant, these marked-up rates yield enormous estimated future removal costs accruals vastly exceeding actual removal expenditures.7

FERC adopted most, but not all, aspects of SFAS No. 143 in its Order No. 631. Although FERC identified non-legal AROs and recognized the need for transparency, it did not require reporting of non-legal AROs as regulatory liabilities. Instead, it required specific identification and separate accounting for these amounts.

FERC Order No. 631 requires that jurisdictional entities maintain separate subsidiary records for cost of removal for non-legal retirement obligations included as specific identifiable allowances recorded in accumulated depreciation. This separately identifies such information to facilitate external reporting as well as for regulatory analysis and rate-setting purposes. Therefore, the commission amended the instructions of accounts 108 in Parts 101 to "require jurisdictional entities to maintain separate subsidiary records for the purposes of identifying the amount of specific allowances collected in rates for non-legal retirement obligations included in the depreciation accruals."8

Although FERC recognized the need for segregation of the non-legal ARO amounts to facilitate external reporting, regulatory analysis, and rate-setting, it left specific recognition of the regulatory liabilities for non-legal AROs up to state PUCs.

It's Up to the PUCs

During its deliberations, FERC considered the comments of several parties. The National Association of State Utility Consumer Advocates (NASUCA) and the accounting firm of Deloitte & Touche suggested that "the commission should make certain modifications to the USOA … to include the amount of cost of removal for non-legal obligations as regulatory liabilities in account 254, other regulatory liabilities, instead of accumulated depreciation."9 The Edison Electric Institute (EEI) and the Southern Co., however, requested, "the commission specify that any cost of removal for non-legal retirement obligations remain in accumulated depreciation."10

FERC followed the latter advice, but required separate subsidiary records of these accruals.11 It concluded, "The issue of whether, and to what extent, a particular asset retirement cost must be recovered through jurisdictional [service] rates should be addressed on a case-by-case basis in the individual rate change filed by public utilities, licensees, and natural-gas companies."12 It "declined to make policy calls concerning regulatory certainty for disposition of … adjustments to book depreciation rates…; these are matters that are not subject to a one-size-fits-all approach and are better resolved on a case-by-case basis in rate proceedings."13

Thus, FERC left the responsibility for recognition of the regulatory liability to state PUCs. It stated that pursuant to commission Order No. 552, "Regulatory assets and liabilities are defined as assets and liabilities that result from ratemaking actions of regulators."14 Although FERC did not make the policy calls for FERC jurisdictional purposes, it recognized that state PUCs are able to make the calls for state jurisdictional purposes.

Therefore, the most important new issue is the need for the state PUCs specifically to recognize a refundable regulatory liability for regulatory reporting, analysis, and ratemaking purposes. While FERC's treatment provides a new transparency, it is not good enough to secure the ratepayers' interests in these amounts.

In recent rate cases, with test years subsequent to the implementation of both SFAS No. 143 and FERC Order No. 631, the existence of these regulatory liabilities has not been disclosed in the filing, notwithstanding that they were reported to the SEC. Such omissions limit the state PUCs' ability to submit these regulatory liabilities to regulatory analysis and address the rate-setting implications.

Whose Money Is It?

Since accumulated depreciation theoretically measures a return of investor-supplied capital, utilities may assent that anything recorded in accumulated depreciation is "their money" because it merely represents a return of "their capital."

However, since ratepayers fronted this money for doubtful future removal expenditures, it is reasonable that they consider it as ratepayer-provided capital, not investor-supplied capital. From the ratepayers' perspective, it should be classified in account 254-Regulatory Liabilities, and recognized as a regulatory liability by regulators. Otherwise, it is at risk of loss to ratepayers.

Even classification as an "other deferred credit," as some utilities have done, is not sufficient on the ratepayers' perspective. Utilities easily can claim a deferred credit belongs to shareholders. Deferred credits defeat the purpose. This is why it must be reiterated that state PUC regulators specifically must recognize the regulatory liabilities resulting from non-legal AROs, and the utilities should report them as such.

For example, 2004 Form 10K from the Tucson Electric Power Co. (TEP) demonstrates why explicit recognition is necessary. TEP applies SFAS No. 71-Accounting for the Effects of Certain Types of Regulation-to its regulated operations. Therefore, it recorded its non-legal AROs as a regulatory liability in its Form 10K.

As of Dec. 31, 2004, TEP had accrued $67 million for the net cost of removal of the interim retirements from its transmission, distribution, and general plant. As of Dec. 31, 2003, TEP had accrued $60 million for these removal costs. The amount is recorded as a regulatory liability.15

However, TEP also states, "If TEP stopped applying FAS 71 to its remaining regulated operations, it would write off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement."16

These words are hauntingly similar to the warnings uttered in Bell Company annual reports before their most recent rate-base cleansing. In 2003, the Bell Operating Companies transferred $11.5 billion of non-legal AROs from their accumulated depreciation accounts into corporate retained earnings as a result of alternative regulation and SFAS No. 143.

It also is ominous that EEI and the American Gas Association (AGA), along with individual utilities, fought so hard to avoid having either the FASB or FERC recognize or report the non-legal removal cost as regulatory liabilities.

If the utility industry is deregulated, or even if alternative forms of regulation are adopted, history suggests that billions of dollars of regulatory liabilities will be transferred into utility income. The amounts will disappear from the scene unless the state PUCs protect them on behalf of ratepayers.

The De-Reg Debacle

Setting history aside, the industry will transfer the regulatory liabilities into income because that is what GAAP requires. If deregulated, the provisions of SFAS No. 71 no longer will apply, and the regulatory liabilities will flow explicitly to GAAP income under the provisions of SFAS No. 143. If there is any doubt, consider what certain electric utilities did when their production plants were deregulated. TEP stated that:

TEP had accrued $113 million for final decommissioning of its generating facilities. … This amount was reversed for 2002 and included as part of the cumulative effect adjustment of accounting adjustment when FAS 143 was adopted on Jan. 1, 2003.17
TEP already has transferred non-legal AROs into income, and if the transmission and distribution business is deregulated or if alternative regulation is adopted, TEP very well may get the rest of the money.18

Several American Electric Power (AEP) production plants were deregulated. AEP immediately transferred $473 million of non-legal dismantlement cost from accumulated depreciation into its income.19

The public utility industries will write off these amounts as soon as they are able. Recognition of the regulatory liabilities for regulatory purposes provides a certain level of protection to ratepayers.

In sum, state PUCs specifically should recognize, as refundable regulatory liabilities, all accruals for non-legal cost of removal and dismantlement. Although FERC Order No. 631 provides a new transparency, it did not establish a regulatory liability for non-legal asset retirement obligations. While it is common knowledge that ratepayers provided these prepayments, there is no regulatory recognition of the liability, and there is no provision for a refund if the utilities do not spend the amounts on their intended purpose.

Consequently, the utilities are not directly accountable for the excess collections. This is unreasonable. Inflation aspects of the TIFCA formula make it highly unlikely that utilities will incur removal costs of the magnitude collected. Nevertheless, even if this money were to be spent for cost of removal, state PUCs specifically should recognize the ratepayers' security interest in these monies until they are spent on their intended purpose. Unless they are explicitly identified as "subject to refund," they are merely hidden potential income to the public utilities, and a large potential loss to ratepayers.


  1. Statement of Financial Accounting Standards No. 71 (SFAS No. 71) - Accounting for the Effects of Certain Types of Regulation, paragraph 11.
  2. Statement of Financial Accounting Standards No. 143 (SFAS 143), Accounting for Asset Retirement Obligations, paragraph 2.
  3. Federal Energy Regulatory Commission, , RM02-7-000, Order No. 631, Issued April 9, 2003 (Order No. 631), paragraph 36.
  4. SFAS 143, paragraph B73.
  5. , paragraph 4.
  6. , paragraph A3.
  7. James G, Campbell and Michael J. Majoros Jr., "What's 'Sunk' Ain't Stranded: Why Excessive Utility Depreciation Is Avoidable," , Vol. 137, No. 7, April 1, 1999, pp. 34-39.
  8. Order No. 631, paragraph 38, (emphasis added).
  9. , paragraph 34, footnote 28.
  10. , footnote 27.
  11. , paragraph 38.
  12. , paragraph 62.
  13. , paragraph 64.
  14. , paragraph 25.
  15. Unisource Energy Corp., De. 31, 2004 10K Report, page K-60.
  16. , page K-59, (Emphasis added).
  17. Id.
  18. The authors understand that the Staff of the Arizona Corporation Commission objects to TEP's so-called reversal.
  19. AEP 2003 Annual Report to Shareholders, p. 69.