After reading Gordon van Welie’s article in your November 2005 issue (“New England: A Critical Look at Competition”) I couldn’t help but think back to California in 2000. Van Welie, who is president and CEO of ISO New England, is trying to feed the citizens of New England the same brand of malarkey that the California ISO fed the California Public Utilities Commission in 2000 when wholesale and retail prices in California were perfectly linked and nearly succeeded in bankrupting the wealthiest state in the country.
Van Welie’s ISO wholesale market in New England is piddling, accounting for approximately 10 percent of the sales in New England. Most sales in New England are done through bi-lateral contracts that have served the citizens of New England fairly well. The further they are from van Welie’s ISO wholesale market, the better off they will be.
What Van Welie’s ISO has succeeded in doing is to make New England vastly dependent on gas-fired generation, and they then have the nerve to explain that one of the reasons New England could have reliability problems this winter is because generators have the choice to use gas to generate electricity or sell it back into the market based on economics. That’s a great deal for consumers. With deals like that as well as the monumental costs of running Van Welie’s outfit and the other ISOs across the country, I doubt if competition will bring any savings to consumers.
Jim Lundrigan, New Haven, Conn.
The Author Responds: Not only is Mr. Lundrigan’s letter misleading, it also misrepresents what is happening in New England. New England’s wholesale market has grown to $7.25 billion in annual transactions in a short period of time. And while approximately 20 to 25 percent of the region’s electricity is sold through the day-ahead and real-time “spot” markets, the bilateral contracts he mentions are rooted in wholesale prices. Moreover, wholesale markets provide value: A recent report by Cambridge Energy Research Associates found that, in the past seven years, U.S. residential consumers paid $34 billion less for electricity than they would have paid if traditional regulation had remained in place.
Mr. Lundrigan blames ISO New England for the region’s growing reliance on natural gas to produce electricity, but we have no authority over siting decisions. This trend—which we issued warnings about as early as January 2001—is the result of well-intentioned state environmental policies that encouraged the development of cleaner power. We have been out front in calling for a diversification of the region’s power sources.
ISO New England’s management of the power system has resulted in significant investment in new power plants, market systems, information, technology, and critically needed transmission projects. This has resulted in a more reliable, economical, and environmentally friendly power system.
The total value of the services we have provided and the resulting savings far exceed our operating costs, which have been approved every year by the region’s stakeholders. We will continue to build a power system to meet the region’s current and future electricity needs and do so in a manner that is cost effective.—Gordon van Welie, CEO, ISO New England
The article of Michael J. Majoros Jr. (“Rate-Base Cleansings: Rolling Over Ratepayers,” November 2005) attracted my attention, because I perceive it to propose a solution—PUCs’ need to recognize refundable regulatory liabilities—for a problem that does not exist.
Majoros’ basic premise is that regulated entities have no obligation to incur costs to remove or safely abandon assets in place, which he refers to as “non-legal AROs” (asset retirement obligations). Regulated entities may not have a legal obligation as is defined by Statement of Financial Accounting Standards (SFAS) 143, Accounting for Asset Retirement Obligations. However, this does not mean that such entities have no obligation to incur costs to remove or safely abandon assets in place. I have long observed such costs being incurred on a regular basis by regulated entities for purposes of public safety and to assure their ability to continue to provide service, even though there is no “legal obligation.” An example is the Southern California Edison Co. (SCE), for which Majoros’ testimony in California Application 04-12-014 shows that during the period 1994 through 2003, SCE incurred cost-of-removal expenditures of $448 million for distribution plant alone. Contrary to Mr. Majoros’ assertion, regulated entities recognize an obligation to incur removal costs and incur such costs on a regular basis.
This obligation is not trivial, as is evident for SCE and from the tabulation on p. 60 of Majoros’ article of the cost of removal that has been accrued by a dozen utilities, and whether it is recorded as a component of the accumulated provision for depreciation (book reserve), as FERC dictates, or as a component of Account 254, Regulatory Liabilities, as Majoros suggests, does not change anything.
Majoros asserts that SFAS 143 “identifies an immediate need for state public service commissions (PUCs) to recognize a refundable regulatory liability for past charges to ratepayers for non-legal retirement costs.” SFAS 143 addresses only legal obligations, and its reference to regulatory liabilities is limited to recognition that entities qualifying for SFAS 71, Accounting for the Effects of Certain Types of Regulation, can include such obligations in depreciation on their income statements and show the amounts therein as regulatory liabilities on their balance sheets. Therefore, Majoros’ assertion about the implications of SFAS 143 is false.
Majoros asserts “the telephone industry has cleansed its rate base twice.” The first event he refers to is when the telephone industry recorded asset impairments during the 1990s, which was accomplished through recording large increases to book reserves. These transactions were in response to recognition that the depreciable lives imposed by regulators were excessive and that this situation meant that the enterprises no longer qualify for the special accounting allowed by SFAS 71. The reserve increases were recorded for financial accounting purposes, but not for regulatory accounting and ratemaking purposes, so contrary to Mr. Majoros’ assertion, rate base was not affected by these transactions.
The second “cleansing” event Majoros refers to is when the cost of removal that had been accumulated in the book reserves was reversed at the time SFAS 143 was adopted. This was done by all regulated entities in response to the position expressed by the Securities and Exchange Commission (SEC) that generally accepted accounting principles (GAAP) dictates cost of removal be expensed at the time incurred, rather than accrued as a component of depreciation. This was done for financial accounting purposes, but not for regulatory accounting and ratemaking purposes, because Uniform Systems of Accounts specify that cost of removal be recorded as a component of depreciation. Majoros notes similar transactions by electric utilities at the time industry restructuring caused certain power plants to no longer qualify for SFAS 71. Contrary to Majoros’ assertion, rate base was not affected by these transactions. I am convinced that the SEC’s interpretation of GAAP is incorrect, for reasons that are beyond the scope of these comments. However, regulated entities are forced to reverse for financial accounting purposes any previously accrued cost of removal for operations no longer qualifying for SFAS 71 for as long as the SEC’s current interpretation of GAAP remains.
The fact that rate base was not affected by these telephone industry actions is demonstrated by a recent proceeding in the state of Washington in which one of Mr. Majoros’ partners testified on depreciation. The proceeding involved the intrastate business of Verizon, and all parties incorporated cost of removal into their proposed depreciation rates and recognized that Verizon’s book reserve for regulatory accounting and ratemaking purposes includes cost of removal. Verizon’s interstate business is subject to Federal Communications Commission (FCC) jurisdiction. The FCC allows depreciation rates to be based on specified ranges of lives and net salvage ratios without question, but allows departure from the ranges upon proof of need. The FCC’s net salvage ranges recognize cost of removal.
Majoros uses a phrase he has coined “Traditional Inflated Future Cost Approach,” which I interpret as implying there is something amiss with how the cost of removal component of depreciation rates is determined. This is an accurate phrase, but the implications Majoros seems to be drawing from it are not correct.
“Inflated” means nothing more than, when past experience is considered in determining the cost of removal expected to be incurred upon the retirement of surviving assets, it is typical to relate the recorded cost of removal to the recorded original cost of the retired assets. This relationship reflects the cost of removal at the price level when incurred and the retired assets at the price level when placed in service. Therefore, labor cost escalation over the asset lifetime is inherent in the relationship.
“Future” means nothing more than depreciation rates being required to reflect future cost of removal, i.e., the expected amount at the price level at the time incurred.
The terminology typically utilized by depreciation analysts and regulators to recognize this situation is “Traditional Method” or “Traditional Approach.”
Majoros notes that increases in depreciation expense cause increases to revenue requirements, but fails to mention that this is a short-term phenomenon. He notes that depreciation expense accumulates in the book reserve, but ignores its influence on revenue requirements. Rate-base regulation causes the initial revenue-requirement impact of any change in depreciation to reverse in the long-term, and it does not take very long for this to occur.
Majoros notes that accrual accounting for cost of removal can result in controversy in regulatory proceedings. This situation is due to accrual accounting, whereby estimated cost of removal expenditures are recorded as an expense ratably over the estimated life of the related assets. This typically results in annual cost of removal accrual amounts in excess of the current annual expenditure amounts, thereby causing some to assert there is something wrong and to propose deferral mechanisms for the recording and recovery of cost of removal. Such mechanisms conflict with commission accounting rules, and have the effect of increasing revenue requirements in the long term and shifting costs to future generations of ratepayers. Cost of removal having the effect of increasing depreciation rates is viewed negatively by those interested only in the short term, and may end up influencing regulators to emphasize the near term. Near-term emphasis is unfortunate for the ratepayers and the economic viability of the service territory, because inadequate depreciation rates causes inadequate book reserves that inflate rate base.
John S. Ferguson, Richardson, Texas
The Author Responds: John Ferguson’s response to my article is not surprising. Mr. Ferguson is a depreciation witness who always represents utilities and advocates for higher and higher depreciation rates. His response to my article attempts to defend the current practice of increasing depreciation rates for inflated future cost of removal estimates.
Excess depreciation is not the primary focus of my article. Its main thrust, as stated in the first sentence, is “the 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.” PUCs should protect collections on behalf of ratepayers until they are used for their intended purpose. What’s wrong with that? It is pure common sense, but Ferguson strongly objects.
He objects because the protection I recommend precludes utilities the opportunity for exorbitant rate-base cleansings. Rate-base cleansings are rate-base increases resulting from transfers of ratepayer-provided capital into corporate equity accounts.
Ferguson is correct that the telecom industry’s most recent rate-base cleansing resulted from the implementation of SFAS No. 143 (i.e., excess cost of removal charges), but he is incorrect about that industry’s first cleansing. The first telecom rate base cleansing was a component of the 1983 AT&T divestiture. Its operating subsidiaries transferred into their corporate equity accounts billions of dollars of ratepayer-provided capital in the form of deferred taxes and investment tax credits.
Additionally, as explained in my current article, electric utilities whose production plants have been deregulated already have cleansed that portion of their rate bases. In other words, regardless of Ferguson’s claims to the contrary, the problem does exist—it is real.
Finally, since Ferguson chose to address a recent proceeding in which I provided testimony (A.04-12-014), it is fair to set the record straight. First, Ferguson was not a witness in the proceeding. Second, Ferguson correctly states that my testimony showed that the company had incurred $448 million of distribution plant cost of removal for the years 1994 to 2003. He fails, however, to inform the reader that my testimony also showed that the company had charged its ratepayers $1.5 billion over and above the $448 million for distribution plant cost of removal. I seek to protect that $1.5 billion excess from a rate-base cleansing until the company actually spends the money on its intended purpose. Again, what’s wrong with that?—Michael J. Majoros Jr.